planners demonstrating a need for capacity benefit margin and (ii)
applicable reserve margin or resource adequacy requirements. In
preparing their studies, Requirements R3.1 and R4.1 direct load-serving
entities and resource planners to use one or more of the following to
determine the generation capability import requirement: (i) Loss of
load expectation studies, (ii) loss of load probability studies, (iii)
deterministic risk-analysis studies, and (iv) applicable reserve margin
or resource adequacy requirements. With regard to the allocation and
use of transmission capacity set aside as capacity benefit margin,
Requirement R1.3 requires the transmission service provider to include
in its capacity benefit margin implementation document the procedure
for a load-serving entity or balancing authority to use transmission
capacity set aside as capacity benefit margin, including the manner in
which the transmission service provider ``will manage'' situations
where the requested use of capacity benefit margin exceeds the capacity
benefit margin available.
b. Commission Proposal
    110. In Order Nos. 890 and 693, the Commission emphasized that each
load-serving entity has the right to request that capacity benefit
margin be set aside, and to use transmission capacity set aside for
that purpose, to meet its verifiable generation reliability criteria
requirement.\78\ The Commission is concerned that, as proposed, the
Reliability Standard would allow a transmission service provider to
calculate, allocate, and use capacity benefit margin in a way that
impairs the reliable operation of the Bulk-Power System. Under the
Reliability Standard, the transmission service provider is to ``reflect
consideration'' of studies provided by load-serving entities and
resource planners demonstrating a need for capacity benefit margin and
``manage'' situations where the requested use of capacity benefit
margin exceeds the capacity benefit margin available. The Reliability
Standard places no bounds on this ``consideration'' and ``management''
and, for example, would permit a transmission service provider to make
decisions regarding the use of capacity benefit margin based solely on
economic considerations notwithstanding a demonstration of need for
capacity benefit margin by a load-serving entity or resource planner.
The Commission proposes, pursuant to section 215(d)(5) of the FPA and
section 39.5(f) of our regulations, to direct the ERO to develop a
modification to the Capacity Benefit Margin Methodology (MOD-004-1) to
ensure that the Reliability Standard would not allow a transmission
service provider to calculate, allocate, and use capacity benefit
margin in a way that impairs the reliable operation of the Bulk-Power
System.
---------------------------------------------------------------------------

    \78\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 1080. see
also Order No. 890, FERC Stats. & Regs. ] 31,241 at P 259; Order No.
890-A, FERC Stats. & Regs. ] 31,261 at P 82.
---------------------------------------------------------------------------

    111. In addition, the Commission has concern regarding references
to applicable reserve margin and resource adequacy requirements in the
determination of the generation capability import requirements by load-
serving entities and resource planners under Requirements R3.1 and
R4.1. Under the phrasing of those provisions, load-serving entities and
resource planners must determine their generation capability import
requirement by using one or more of loss of load expectation studies,
loss of load probability studies, deterministic risk-analysis studies,
and applicable reserve margin or resource adequacy requirements. As a
result, a load-serving entity or resource planner could rely solely on
reserve margin and resource adequacy requirements to demonstrate a need
for capacity benefit margin without any analysis of loss of load
expectations, loss of load probabilities, or deterministic risk. In
comparison, Requirements 5.1 and 6.1 obligate the transmission service
provider to consider both the studies provided by load-serving entities
and resource planners and applicable reserve margin and resource
adequacy requirements when calculating capacity benefit margin and
allocating it to particular paths or flowgates. The Commission
proposes, pursuant to section 215(d)(5) of the FPA and section 39.5(f)
of our regulations, to direct the ERO to develop a modification to MOD-
004-1 to require load-serving entities and resource planners to
determine generation capability import requirements by reference to
relevant studies and applicable reserve margin or resource adequacy
requirements, as relevant.
4. Calculation of Total Transfer Capability Under the Rated System Path
Methodology (MOD-029-1)
a. NERC Proposal
    112. Requirement R2 of the Rated System Path Methodology (MOD-029-
1) provides the process a transmission operator must use to determine
total transfer capability. Requirement R2.7 of that Reliability
Standard requires the transmission operator to set the total transfer
capability of an available transfer capability path to a value

determined prior to 1994 in certain instances:

    R2.7. For available transfer capability Paths whose path rating,
adjusted for seasonal variance, was established, known and used in
operation since January 1, 1994, and no action has been taken to
have the path rated using a different method, set the total transfer
capability at that previously established amount.
b. Commission Proposal
    113. In Order No. 890, the Commission required the use of
consistent practices to calculate total transfer capability.\79\ In
Order No. 890-A, the Commission clarified that, while total transfer
capability need not be recalculated at consistent time intervals, the
transmission operator should consider whether any changes in system
topology, contingency outages, or other factors are substantial enough
to merit recalculation of total transfer capability.\80\
---------------------------------------------------------------------------

    \79\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 237.
    \80\ Order No. 890-A, FERC Stats. & Regs. ] 31,261 at P 105.
---------------------------------------------------------------------------

    114. NERC has not explained the inclusion of Requirement R2.7 in
the Rated System Path Methodology. It is not clear to the Commission
why certain applicable entities would be required to use pre-1994 total
transfer capability values. The Commission is concerned that requiring
pre-1994 total transfer capability values to remain in place without
adequate explanation essentially exempts certain paths from the total
transfer capability requirements in the Rated System Path Methodology
and may result in total transfer capability values that are incorrectly
based on stale assumptions and criteria.
    115. While the Commission proposes to approve the proposed
Reliability Standard overall as just and reasonable and an improvement
on available transfer capability transparency, as discussed above,
pursuant to section 215(d)(5) of the FPA and section 39.5(f) of our
regulations, the Commission seeks comment on whether it should direct
the ERO to develop a modification to the Rated System Path Methodology
(MOD-029-1) to remove Requirement R2.7 as unsupported.
5. Treatment of Network Resource Designations
a. NERC Proposal
    116. In each of the proposed Reliability Standards, transmission
service providers are required to identify as part of their calculation
of existing transmission commitments the amount of capacity that is set
aside for network integration transmission service.\81\ However, the
specificity of that requirement varies among the proposed Reliability
Standards.
---------------------------------------------------------------------------

    \81\ See MOD-028-001, Requirement R8; MOD-029-1, Requirement R5;
MOD-030-2, Requirement R6.1.
---------------------------------------------------------------------------

    117. Under the Flowgate Methodology (MOD-030-2), Requirements R6.1
and 6.2 provide for calculation of the impact of network integration
transmission service based on a modeling of load forecasts for the time
period being calculated and unit commitment and dispatch order,
including all designated network resources and other resources that are
committed or have the legal obligation to run as specified in the
transmission service provider's implementation document. Requirement R8
of the Area Interchange Methodology (MOD-028-1) and Requirement R5 of
the Rated System Path Methodology (MOD-029-1) provide for the inclusion
of firm capacity reserved for network integration transmission service,
but do not describe how the transmission service provider is to
identify that amount of capacity.
    118. With regard to the frequency of these calculations,
Requirement R8 of MOD-001-1 would require every transmission service
provider calculating available transfer capability to perform
recalculations of available transfer capability at specified
frequencies, unless none of the calculated values identified in the
available transfer capability equation have changed.
b. Commission Proposal
    119. In Order No. 693, the Commission directed the ERO to develop
requirements specifying how transmission service providers should
determine which generators should be modeled in service when
calculating available transfer capability.\82\ Among other things, the
Commission directed the ERO to revise the Reliability Standards to
specify that base generation dispatch schedules will reflect the
modeling of all designated network resources and other resources that
are committed to or have the legal obligation to run, as they are
expected to run. The Commission also directed transmission service
providers to address the effect on available transfer capability of
designating and undesignating a network resource.
---------------------------------------------------------------------------

    \82\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 1041.
---------------------------------------------------------------------------

    120. NERC has not explained the failure to include in each of the
available transfer capability methodologies a requirement that base
generation dispatch schedules will reflect the modeling of all
designated network resources and other resources that are committed to
or have the legal obligation to run, as they are expected to run. It is
therefore unclear whether the proposed Reliability Standards address
the effect on available transfer capability of designating and
undesignating a network resource. While the Commission proposes to
approve the proposed Reliability Standards as just and reasonable and
an improvement on available transfer capability transparency, pursuant
to section 215(d)(5) of the FPA and section 39.5(f) of our regulations,
the Commission proposes to direct the ERO to develop a modification to
the Reliability Standards to address these requirements.

C. Violation Risk Factors and Violation Severity Levels

    121. To determine a base penalty amount for a violation of a
requirement within a Reliability Standard, NERC must first determine an
initial range for the base penalty amount. To do so, NERC will assign a
violation risk factor for each requirement of a Reliability Standard
that relates to the expected or potential impact of a violation of the
requirement on the reliability of the Bulk-Power System. For that
requirement, the ERO assigns a lower, medium or high violation risk
factor for each mandatory Reliability Standard requirement.\83\ The
Commission has established guidelines for evaluating the validity of
each violation risk factor assignment.\84\
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    \83\ The specific definitions of high, medium and lower are
provided in North American Electric Reliability Corp., 119 FERC ]
61,145 at P 9, order on reh'g, 120 FERC ] 61,145 (2007) (Violation
Risk Factor Rehearing Order).
    \84\ The guidelines are: (1) Consistency with the conclusions of
the blackout report; (2) consistency within a Reliability Standard;
(3) consistency among Reliability Standards; (4) consistency with
NERC's definition of the violation risk factor level; and (5)
treatment of requirements that co-mingle more than one obligation.
The Commission also explained that this list was not necessarily
all-inclusive and that it retained the flexibility to consider
additional guidelines in the future. A detailed explanation is
provided in the Violation Risk Factor Rehearing Order, 120 FERC ]
61,145 at P 8-13.
---------------------------------------------------------------------------

    122. NERC will also define up to four violation severity levels--
lower, moderate, high and severe--as measurements for the degree to
which the requirement was violated in a specific circumstance. For a
specific violation of a particular requirement, NERC or the Regional
Entity will establish the initial value range for the base penalty
amount by finding the intersection of the applicable violation

risk factor and violation severity level in the base penalty amount
table in appendix A of its sanction guidelines.
    123. On June 19, 2008, the Commission issued an order establishing
four guidelines for the development of violation severity levels.\85\
First, the violation severity level assignments should not have the
unintended consequence of lowering the current level of compliance.
Second, the violation severity levels should ensure uniformity and
consistency in the determination of penalties. Third, a violation
severity level assignment should be consistent with the corresponding
requirement. Fourth, a violation severity level assignment should be
based on a single violation, not on a cumulative number of violations.
---------------------------------------------------------------------------

    \85\ North American Electric Reliability Corp., 123 FERC ]
61,284, at P 20-35 (Violation Severity Level Order), order on reh'g
& compliance, 125 FERC ] 61,212 (2008).
---------------------------------------------------------------------------

1. NERC Proposal
    124. In its August 29, 2008 filing, NERC proposes violation
severity levels that are specific to the individual requirements of the
proposed Reliability Standards. NERC states that it developed violation
severity level assignments for MOD-001-1, MOD-008-1, MOD-028-1, MOD-
029-1, and MOD-030-1 prior to issuance of the Violation Severity Level
Order. As a result, NERC states that it has not analyzed the proposed
violation severity levels relative to the Commission's guidelines
established in the Violation Severity Level Order.
    125. In addition, NERC states that it is not filing the associated
violation risk factors with these Reliability Standards. While
violation risk factors have been developed and balloted for each of the
five proposed Reliability Standards, NERC states that its Board
believes further review of the violation risk factors is warranted
given recent Commission actions in general and the development history
of these violation risk factors in particular. In accordance with its
Rules of Procedure, NERC states that it will submit violation risk
factors for these proposed Reliability Standards in a future filing.
    126. NERC states that each balloted Reliability Standard included a
violation risk factor for each main requirement in the Reliability
Standard. For all the requirements in the balloted MOD Reliability
Standards, the applicable violation risk factors were ``lower.'' In
developing the violation risk factor assignments, NERC states that
there were opposing viewpoints with respect to the appropriate
assignments. According to NERC, one view offered that available
transfer capability and its associated methodologies do not directly
affect the electrical state of the system or the ability to monitor or
control it as would be required under the ``medium'' violation risk
factor assignment. NERC states that an incorrect available transfer
capability calculation may lead to oversubscribing or undersubscribing
the system. According to NERC, undersubscribing, while affecting the
potential for commercial activity, actually benefits reliability.
Oversubscribing the system as a result of an optimistic available
transfer capability value, while somewhat beneficial to commercial
activity, may lead to a reliability concern that if realized can be
managed by the operator's adherence to system limits, to the extent
that the operator has options to implement some measure of transmission
loading relief to reduce flows due to transactions. NERC states that
for an incorrect available transfer capability to become a reliability
issue requires an optimistic available transfer capability value,
coupled with the sale of that available transfer capability, and an
operator who is not mindful to the system limits, the last of which is
governed by other transmission operator and interconnection operating
Reliability Standards. On this argument, according to NERC, assigning a
``medium'' violation risk factor due to the ``direct'' impact is
questionable.
    127. On this basis, the drafting team evaluated the scope of the
remaining work to meet the Commission deadline and focused its
attention to the technical issues, adjusting the violation risk factors
to ``lower'' based on the industry comments and the arguments presented
above. However, NERC states that its Board believes that a more
thorough review of the violation risk factors is warranted given recent
Commission actions in general and the development history of these
violation risk factors in particular. NERC's board has asked NERC staff
to review these violation risk factors through an open stakeholder
process to ensure that they are consistent with the intent of the
violation risk factor definitions and prior Commission decisions on
violation risk factors. Accordingly, NERC states that it is not filing
the associated violation risk factors with these Reliability Standards
at this time. NERC states that it will submit violation risk factors
for these proposed Reliability Standards in a future filing.
    128. In its November 21, 2008 and March 6, 2009 filings, NERC
proposes violations severity levels for MOD-004-1 and MOD-030-2,
respectively. Similar to the violation severity levels proposed for
MOD-001-1, MOD-008-1, MOD-028-1, MOD-029-1, and MOD-030-1, NERC does
not propose any violation severity levels for the sub-requirements. In
addition, NERC states that its board of trustees deferred action on the
violation risk factors associated with these Reliability Standards and
asked that they be reviewed through an open stakeholder process, with a
report back to the board, to ensure that they are consistent with the
intent of the violation risk factor definitions and Commission
precedent. NERC states that it will submit violation risk factors for
these Reliability Standards in a future filing.
2. Commission Proposal
    129. The Commission proposes to accept NERC's commitment to file
violation severity levels and violation risk factors at a later time.
The Violation Severity Level Order was issued after NERC developed the
violation severity level assignments for the Reliability Standards at
issue in this proceeding. As a result, NERC was unable to evaluate and
modify the proposed violation severity levels to comply with our
guidelines prior to filing the proposed Reliability Standards. The
Commission proposes 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 proposes 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 definitions and guidance provided in the
Violation Risk Factor Order and the Violation Risk Factor Rehearing
Order. The Commission proposes to direct NERC to file revised violation
severity levels and violation risk factors no later than 120 days
before the Reliability Standards become effective.

D. Disposition of Other Reliability Standards

1. MOD-010-1 through MOD-025-1
    130. Order No. 890 directed public utilities, working through NERC,
to modify the reliability standards MOD-010 through MOD-025 \86\ to
incorporate

a requirement for the 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. The
Commission found that this requirement is essential in order to have an
accurate simulation of the performance of the grid and from which to
comparably calculate available transfer capability, therefore
increasing transparency and decreasing the potential for undue
discrimination by transmission service providers.\87\
---------------------------------------------------------------------------

    \86\ The MOD-010 through MOD-025 Reliability Standards establish
data requirements, reporting procedures, and system model
development and validation for use in the reliability analysis of
the interconnected transmission systems.
    \87\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 290.
---------------------------------------------------------------------------

a. NERC Proposal
    131. NERC states that this modeling activity is outside the scope
of the available transfer capability Reliability Standards drafting
team effort because it requires a different skill set and expertise
than that required for developing available transfer capability and
should be addressed by a separate drafting team. NERC states that these
Reliability Standards are part of its Reliability Standards Development
Plan. NERC states that this is consistent with Order No. 693, which
identified nine Reliability Standards, none of which were MOD-010
through MOD-025, as the core of the available transfer capability
initiative directed in Order No. 890.\88\
---------------------------------------------------------------------------

    \88\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 206.
---------------------------------------------------------------------------

b. Commission Proposal
    132. The Commission proposes to allow NERC to address revisions to
MOD-010 through MOD-025 through a separate project. Those Reliability
Standards are generally intended to establish consistent data
requirements, reporting procedures and system models for use in
reliability analysis. As such, the Commission proposes to find that
NERC is correct that they were not a part of the available transfer
capability modifications required in Order Nos. 890 and 693.
2. Reliability Standards Proposed To Be Retired or Withdrawn
a. NERC Proposal
    133. NERC requests that FAC-013-1, MOD-006-0, and MOD-007-0 be
retired when the available transfer capability-related Reliability
Standards become effective. In addition, NERC requests to withdraw its
request for approval of the following Reliability Standards that were
neither approved nor remanded in Order No. 693, effective upon approval
of the available transfer capability-related MOD Reliability Standards
in this proceeding: FAC-012-1, MOD-001-0, MOD-002-0, MOD-003-0, MOD-
004-0, MOD-005-0, MOD-008-0, and MOD-009-0. According to NERC, these
Reliability Standards are wholly superseded by the MOD Reliability
Standards addressed in this proceeding.
b. Commission Proposal
    134. The Commission proposes 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 proposes 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
and are, upon the effectiveness of the proposed MOD Reliability
Standards, no longer necessary.
    135. With regard to FAC-012-1 and FAC-013-1, the Commission
disagrees with NERC that these Reliability Standards are wholly
superseded by the MOD Reliability Standards addressed in this
proceeding. 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. 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. In comparison, 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.\89\ 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.
---------------------------------------------------------------------------

    \89\ See MOD-001-1, Requirement R2.3.
---------------------------------------------------------------------------

    136. 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.\90\ 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.\91\ 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.\92\
---------------------------------------------------------------------------

    \90\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 777.
    \91\ Id. P 782.
    \92\ Id. P 779, 782.
---------------------------------------------------------------------------

    137. The available transfer capability methodologies set forth in
MOD-028-1, MOD-029-1, and MOD-030-2 each provide a framework for the
calculation of total transfer capability and total flowgate capability
that specifies certain data inputs and modeling assumptions to be
used.\93\ Requirement R7 of MOD-001-1 also provides that, when
calculating available transfer capability or available flowgate
capability, the transmission provider shall use assumptions no more
limiting than those used in the planning of operations for the
corresponding time period studied. It therefore appears that the MOD
Reliability Standards provide a framework for the consistent
calculation of total transfer capability for the operating horizon.
However, NERC has not addressed the requirements of Order No. 693 with
regard to the calculation of transfer capabilities in the planning
horizon.
---------------------------------------------------------------------------

    \93\ See MOD-028-1, Requirements R3 and R4; MOD-029-1,
Requirements R2 and R3; MOD-030-2, Requirement R2.4.
---------------------------------------------------------------------------

    138. The Commission therefore proposes not to grant NERC's request
to withdraw FAC-012-1, nor approve the retirement of FAC-013-1.
Instead, the Commission proposes, pursuant to section 215(d)(5) of the
FPA and section 39.5(f) of our regulations, to direct the ERO to submit
a revised FAC-012-1 and a modification to FAC-013-1 to comply with the
relevant directives of Order No. 693 and as otherwise necessary to make
the requirements of those Reliability Standards consistent with those
of the proposed MOD Reliability Standards and the final rule in this
proceeding. The Commission proposes to direct the ERO to submit a
revised FAC-012-1 and a modification

to FAC-013-1, as well as violation severity levels and violation risk
factors for FAC-012-1 and FAC-013-1, no later than 120 days before the
MOD Reliability Standards become effective.

E. Definitions

    139. In Order Nos. 890 and 693, the Commission noted that there was
not a definition of available flowgate capability/total flowgate
capability in the ERO's glossary and directed the ERO to develop
available flowgate capability/total flowgate capability definitions
used to identify a particular set of transmission facilities as
flowgates.
1. NERC Proposal
    140. NERC proposes to modify its Glossary of Terms to add the
following twenty definitions that are used in the five proposed
Reliability Standards, two of which wholly replace existing terms in
the Commission-approved NERC Glossary: \94\
---------------------------------------------------------------------------

    \94\ These include Available Transfer Capability and Flowgate.

    Area Interchange Methodology: The Area Interchange Methodology
is characterized by determination of incremental transfer capability
via simulation, from which Total Transfer Capability (TTC) can be
mathematically derived. Capacity Benefit Margin (CBM), Transmission
Reliability Margin (TRM), and Existing Transmission Commitments
(ETC) are subtracted from the TTC, and Postbacks and counterflows
are added, to derive Available Transfer Capability (ATC). Under the
Area Interchange Methodology, TTC results are generally reported on
an area to area basis.
    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.\95\
---------------------------------------------------------------------------

    \95\ See 18 CFR 37.6(b)(1) (2008).
---------------------------------------------------------------------------

    Available Flowgate Capability (AFC): A measure of the flow
capability remaining on a Flowgate for further commercial activity
over and above already committed uses. It is defined as Total
Flowgate Capability (TFC) less Existing Transmission Commitments
(ETC), less a Capacity Benefit Margin (CBM), less a Transmission
Reliability Margin (TRM), plus Postbacks, and plus counterflows.
    Available Transfer Capability (ATC): A measure of the transfer
capability remaining in the physical transmission network for
further commercial activity over and above already committed uses.
It is defined as Total Transfer Capability (TTC) less Existing
Transmission Commitments (ETC) (including retail customer service),
less a Capacity Benefit Margin (CBM), less a Transmission
Reliability Margin (TRM), plus Postbacks, plus counterflows.
    Available Transfer Capability Implementation Document (ATCID): A
document that describes the implementation of a methodology for
calculating Available Transfer Capability (ATC) or Available
Flowgate Capability (AFC), and provides information related to a
Transmission Service Provider's calculation of ATC or AFC.
    Block Dispatch: A set of dispatch rules such that given a
specific amount of load to serve, an approximate generation dispatch
can be determined. To accomplish this, the capacity of a given
generator is segmented into loadable ``blocks,'' each of which is
grouped and ordered relative to other blocks (based on
characteristics including, but not limited to, efficiency, run of
river or fuel supply considerations, and/or ``must-run'' status).
    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.
    Capacity Benefit Margin Implementation Document (CBMID): A
document that describes the implementation of a Capacity Benefit
Margin methodology.
    Dispatch Order: A set of dispatch rules such that given a
specific amount of load to serve, an approximate generation dispatch
can be determined. To accomplish this, each generator is ranked by
priority.
    Existing Transmission Commitments (ETC): Committed uses of a
Transmission Service Provider's Transmission system considered when
determining Available Transfer Capability (ATC) or Available
Flowgate Capability (AFC).
    Flowgate:
    (1) A portion of the Transmission system through which the
Interchange Distribution Calculator calculates the power flow from
Interchange Transactions.
    (2) A mathematical construct, comprised of one or more monitored
transmission Facilities and optionally one or more contingency
Facilities, used to analyze the impact of power flows upon the Bulk
Electric System.
    Flowgate Methodology: The Flowgate methodology is characterized
by identification of key Facilities as Flowgates. Total Flowgate
Capabilities (TFC) are determined based on Facility Ratings and
voltage and stability limits. The impacts of Existing Transmission
Commitments (ETCs) are determined by simulation. The impacts of ETC,
Capacity Benefit Margin (CBM) and Transmission Reliability Margin
(TRM) are subtracted from the TFC, and Postbacks and counterflows
are added, to determine the Available Flowgate Capability (AFC)
value for that Flowgate. AFCs can be used to determine Available
Transfer Capability (ATC).
    Generation Capability Import Requirement (GCIR): The amount of
generation capability from external sources identified by a Load-
Serving Entity (LSE) or Resource Planner (RP) to meet its generation
reliability or resource adequacy requirements as an alternative to
internal resources.
    Outage Transfer Distribution Factor (OTDF): In the post-
contingency configuration of a system under study, the electric
Power Transfer Distribution Factor (PTDF) with one or more system
Facilities removed from service (outaged).
    Participation Factors: A set of dispatch rules such that given a
specific amount of load to serve, an approximate generation dispatch
can be determined. To accomplish this, generators are assigned a
percentage that they will contribute to serve load.
    Planning Coordinator: See Planning Authority.
    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.
    Power Transfer Distribution Factor (PTDF): In the pre-
contingency configuration of a system under study, a measure of the
responsiveness or change in electrical loadings on transmission
system Facilities due to a change in electric power transfer from
one area to another, expressed in percent (up to 100%) of the change
in power transfer.
    Rated System Path Methodology: The Rated System Path Methodology
is characterized by an initial Total Transfer Capability (TTC),
determined via simulation. Capacity Benefit Margin (CBM),
Transmission Reliability Margin (TRM), and Existing Transmission
Commitments (ETC) are subtracted from TTC, and Postbacks and
counterflows are added as applicable, to derive Available Transfer
Capability (ATC). Under the Rated System Path Methodology, TTC
results are generally reported as specific transmission path
capabilities.
    Total Flowgate Capability (TFC): The maximum flow capability on
a Flowgate, is not to exceed its thermal rating, or in the case of a
flowgate used to represent a specific operating constraint (such as
a voltage or stability limit), is not to exceed the associated
System Operating Limit.
    Transmission Operator Area: The collection of Transmission
assets over which the Transmission Operator is responsible for
operating.
    Transmission Reliability Margin Implementation Document (TRMID):
A document that describes the implementation of a Transmission
Reliability Margin (TRM) methodology, and provides information
related to a Transmission Operator's calculation of TRM.
2. Commission Proposal
    141. The Commission proposes to approve the addition of these terms
to the NERC Glossary with minor modification. The Commission believes
that the definition of Postback is not fully determinative. NERC should
be able to define this term without reference to Business Practices,
another defined term. The Commission therefore proposes to direct NERC
to modify the definition of Postback.
    142. The definition of Business Practices includes a reference to
the ``regional reliability organization.'' 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.\96\ Accordingly, the Commission proposes 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. However, Regional Entity is not currently defined
in the NERC Glossary. The Commission therefore proposes to direct NERC
to develop a definition of Regional Entity consistent with section
215(a) of the FPA \97\ and 18 CFR 39.1 (2008), to be included in the
NERC Glossary.
---------------------------------------------------------------------------

    \96\ Order No. 693, FERC Stats. & Regs.] 31,242 at P 157.
    \97\ 16 U.S.C. 824o.
---------------------------------------------------------------------------

IV. Information Collection Statement

    143. The following collections of information contained in this
proposed 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.\98\ OMB's regulations require OMB to approve
certain information collection requirements imposed by agency rule.\99\
---------------------------------------------------------------------------

    \98\ 44 U.S.C. 3507(d).
    \99\ 5 CFR 1320.11.
---------------------------------------------------------------------------

    144. Comments are solicited on the need for this information,
whether the information will have practical utility, ways to enhance
the quality, utility, and clarity of the information to be collected,
and any suggested methods for minimizing respondents' burden, including
the use of automated information techniques.
    Burden Estimate: The public reporting and records retention burdens
for the proposed reporting requirements and the records retention
requirement are as follows.\100\
---------------------------------------------------------------------------

    \100\ These burden estimates apply only to this NOPR 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)

    OMB's regulations require it to approve certain information
collection requirements imposed by an agency rule. The Commission is
submitting notification of this proposed 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: Proposed Collections.
    OMB Control Nos. [to be determined].
    Respondents: Business or other for profit.
    Frequency of responses: On occasion.
    Necessity of the Information:
    145. Internal Review: The Commission has reviewed the proposed
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.
    146. 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: (202) 502-
8415, fax:<PHONE_NUMBER>, e-mail<EMAIL_ADDRESS>    147. 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

    148. 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.\101\ 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.\102\
---------------------------------------------------------------------------

    \101\ Regulations Implementing the National Environmental Policy
Act, Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs.
] 30,783 (1987).
    \102\ 18 CFR 380.4(a)(5).
---------------------------------------------------------------------------

VI. Regulatory Flexibility Act Certification

    149. The Regulatory Flexibility Act of 1980 (RFA) \103\ 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, most of which do not fall within the
definition of small entities.\104\
---------------------------------------------------------------------------

    \103\ 5 U.S.C. 601-612.
    \104\ 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).
---------------------------------------------------------------------------

    150. 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.\105\ The Commission does not consider this a substantial
number.\106\ Based on this understanding, the Commission certifies that
this rule will not have a significant economic impact on a substantial
number of small entities. Accordingly, no regulatory flexibility
analysis is required.
---------------------------------------------------------------------------

    \105\ Id.
    \106\ The Regulatory Flexibility Act defines a ``small entity''
as ``one which is independently owned and operated and which is not
dominant in its field of operation.'' See 5 U.S.C. 601(3) and
601(6); 15 U.S.C. 632(a)(1). In Mid-Tex Elec. Coop. v. FERC, 773
F.2d 327, 340-43 (DC Cir. 1985), the court accepted the Commission's
conclusion that, since virtually all of the public utilities that it
regulates do not fall within the meaning of the term small entities
as defined in the Regulatory Flexibility Act, the Commission did not
need to prepare a regulatory flexibility analysis in connection with
its proposed rule governing the allocation of costs for construction
work in progress (CWIP). The CWIP rules applied to all public
utilities. The revised pro forma OATT will apply only to those
public utilities that own, control or operate interstate
transmission facilities. These entities are a subset of the group of
public utilities found not to require preparation of a regulatory
flexibility analysis for the CWIP rule.
---------------------------------------------------------------------------

VII. Comment Procedures

    151. The Commission invites interested persons to submit comments
on the matters and issues proposed in this notice to be adopted,
including any related matters or alternative proposals that commenters
may wish to discuss. Comments are due May 26, 2009. Comments must refer
to Docket Nos. RM08-19-000, RM08-19-001, RM09-5-000 and RM06-16-005,
and must include the commenter's name, the organization they represent,
if applicable, and their address in their comments.
    152. The Commission encourages comments to be filed electronically
via the eFiling link on the Commission's Web site at http://
www.ferc.gov. The Commission accepts most standard word processing
formats. Documents created electronically using word processing
software should be filed in native applications or print-to-PDF format
and not in a scanned format. Commenters filing electronically do not
need to make a paper filing.
    153. Commenters that are not able to file comments electronically
must send an original and 14 copies of their comments to: Federal
Energy Regulatory Commission, Secretary of the Commission, 888 First
Street NE., Washington, DC 20426.
    154. All comments will be placed in the Commission's public files
and may be viewed, printed, or downloaded remotely as described in the
Document Availability section below. Commenters on this proposal are
not required to serve copies of their comments on other commenters.

VIII. Document Availability

    155. 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.
    156. 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.
    157. 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>
    By direction of the Commission.
Kimberly D. Bose,
Secretary.
 [FR Doc. E9-6505 Filed 3-24-09; 8:45 am]

BILLING CODE 6717-01-P


[Federal Register Volume 82, Number 248 (Thursday, December 28, 2017)]
[Rules and Regulations]
[Page 61452]
[FR Doc No: 2017-27969]

=======================================================================
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DEPARTMENT OF HOMELAND SECURITY

Coast Guard

33 CFR Part 117

[Docket No. USCG-2017-0161]

Drawbridge Operation Regulation; Canaveral Barge Canal,
Canaveral, FL

AGENCY: Coast Guard, DHS.

ACTION: Notice of deviation from drawbridge regulation.

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

SUMMARY: The Coast Guard has issued a temporary deviation from the
operating schedule that governs the SR 401 Drawbridges, mile 5.5 at
Port Canaveral, Florida. The deviation is necessary to reduce vehicular
traffic congestion and to ensure the safety of roadways while
passengers are transiting to and from the cruise ship terminals. Since
the arrival of additional cruise ships to the Port of Canaveral,
massive traffic back-ups have been caused by the on demand drawbridge
openings. This deviation allows the bridges to not open to navigation
during prime cruise ship passenger loading and unloading times on
Saturdays and Sundays.

DATES: This deviation is effective without actual notice from December
28, 2017 through January 31, 2018. For the purposes of enforcement,
actual notice will be used from December 5, 2017, until December 28,
2017.

ADDRESSES: The docket for this deviation, USCG-2017-0161 is available
at http://www.regulations.gov. Type the docket number in the ``SEARCH''
box and click ``SEARCH''. Click on Open Docket Folder on the line
associated with this deviation.

FOR FURTHER INFORMATION CONTACT: If you have questions on this
temporary deviation, call or email LT Allan Storm, Sector Jacksonville,
Waterways Management Division, U.S. Coast Guard; telephone 904-714-
7616, email [email protected].

SUPPLEMENTARY INFORMATION: The Canaveral Port Authority, with
concurrence from the bridge owner, Florida Department of Transportation
have requested the Coast Guard consider allowing the SR 401 Drawbridges
across the Canaveral Barge Canal, Port Canaveral, Florida to not open
to navigation from 11 a.m. to 2 p.m. on Saturdays and Sundays.
    On October 23, 2017 the Coast Guard published a notice of proposed
rulemaking entitled ``Drawbridge Operation Regulation; Canaveral Barge
Canal, Canaveral, FL in the Federal Register (82 FR 48940). Under that
proposed rule, the bridges would remain in the closed-to-navigation
position from 11 a.m. to 2 p.m. on Saturdays and Sundays. The existing
regulation for the SR 401 Drawbridges, across Canaveral Barge Canal,
mile 5.5 at Port Canaveral, FL is published in 33 CFR 117.273(b). The
SR 401 Drawbridges provide a vertical clearance of 25 feet in the
closed position at Mean High Water (MHW) and a horizontal clearance of
90 feet between fenders. The bridge logs from October 2017 indicate
that, at most, approximately nine vessels may be affected by
establishing this three hour bridge closure on Saturdays and Sundays.
The majority of the opening requests were either at the beginning or
end of this closure period; therefore, by adjusting their transits
slightly there should be a negligible overall effect. This temporary
deviation is effective from December 28, 2017 until January 31, 2018.
The Coast Guard will continue to evaluate the impact to mariners
navigating this area during the closure periods.
    Vessels able to pass through the bridge in the closed position may
do so at any time. The bridge will be able to open for emergencies and
there is no immediate alternate route for vessels to pass through the
bridge in closed position. The Coast Guard will also inform the users
of the waterways through our Local and Broadcast Notices to Mariners of
the change in operating schedule for the bridge so that vessel
operators can arrange their transits to minimize any impact caused by
the temporary deviation.
    In accordance with 33 CFR 117.35(e), the drawbridge must return to
its regular operating schedule immediately at the end of the effective
period of this temporary deviation. This deviation from the operating
regulations is authorized under 33 CFR 117.35.

    Dated: December 5, 2017.
Barry Dragon,
Director, Bridge Branch, Seventh Coast Guard District.
[FR Doc. 2017-27969 Filed 12-27-17; 8:45 am]
 BILLING CODE 9110-04-P


Janet Cakir/RTP/USEPA/US

02/14/2008 04:41 PM

To

"King, Heidi R."<EMAIL_ADDRESS> cc

Subject

powerpoint materials for our meeting on costs of our primary analysis on Tues 2/19 at 11:30

Let me know if you have any trouble with the file...

Thanks,

Janet

_______________________________________

Janet F. Cakir, Ph.D.

Environmental Protection Specialist

Air Benefits Cost Group

109 TW Alexander Dr., (C439-02)

Research Triangle Park, NC 27711

Tel:<PHONE_NUMBER>

Fax:<PHONE_NUMBER>

email<EMAIL_ADDRESS>


[Federal Register Volume 87, Number 100 (Tuesday, May 24, 2022)]
[Notices]
[Page 31604]
[FR Doc No: 2022-11083]

=======================================================================
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DEPARTMENT OF TRANSPORTATION

Federal Aviation Administration

Notice of Release of Land Affecting Federal Grant Assurance
Obligations at Reno-Stead Airport, Reno, Washoe County, Nevada

AGENCY: Federal Aviation Administration, DOT.

ACTION: Notice of request to release airport land.

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SUMMARY: The Federal Aviation Administration (FAA) is considering a
proposal and invites public comment to change a portion of the airport
from aeronautical use to non-aeronautical use at the Reno-Stead Airport
(RTS), Reno, Washoe County, Nevada. The proposal consists of
approximately 178.5 acres at the southwest end of the RTS property
between Army Aviation Drive and Rail Spur Road at the airport property
line.

DATES: Comments must be received on or before June 23, 2022.

ADDRESSES: Comments on the request may be mailed or delivered to the
FAA at the following address: Mr. Mike N. Williams, Manager, Phoenix
Airports District Office, Federal Aviation Administration, 3800 N
Central Ave., Suite 1025, 10th Floor, Phoenix, Arizona 85012. In
addition, one copy of the comment submitted to the FAA must be mailed
or delivered to Daren Griffin, President/CEO, Reno-Tahoe Airport
Authority, P.O. Box 12490, Reno, Nevada 89510-2490.

SUPPLEMENTARY INFORMATION: The land was originally acquired by the City
of Reno through the Federal Property and Administrative Services Act of
1947 and the Surplus Property Act of 1944, by the Administrator of
General Services on December 19, 1966, with corrected Quitclaim Deeds
on August 29, 1967 and August 14, 1968. The land was transferred to the
Washoe County Airport Authority by the City of Reno on June 25, 1979.
The land will be released from aeronautical obligations for a future
non-aeronautical use. Such use of the land represents a compatible land
use that will not interfere with the airport or its operation, thereby
protecting the interests of civil aviation. The airport will be
compensated for the fair market value of the use of the land.
    In accordance with the Wendell H. Ford Aviation Investment and
Reform Act for the 21st Century (AIR 21), Public Law 10-181 (Apr. 5,
2000; 114 Stat. 75), this notice must be published in the Federal
Register 30 days before the DOT Secretary may waive any condition
imposed on a federally obligated airport by surplus property conveyance
deeds or grant agreements.

    Issued in El Segundo, California, on May 18, 2022.
Brian Q. Armstrong,
Manager, Safety and Standards Branch, Airports Division, Western-
Pacific Region.
[FR Doc. 2022-11083 Filed 5-23-22; 8:45 am]
BILLING CODE 4910-13-P