in-the-blank standards. EPSA considers the fill-in-the-blank standards
vitally important to reliability and competitive markets and worries
that progress may be lost while the regions endeavor to file the
additional required information.
ii. Commission Determination
    1011. The Commission will adopt the NOPR proposal and retain the
same disposition of the MOD Reliability Standards that it proposed
there. We confirm in this Final Rule that one out of 23 MOD standards
is approved unconditionally, nine are approved with direction for
modification and 13 remain pending with direction for modification. We
will discuss our rationale for this decision in the Commission
Determination section for each particular Reliability Standard.
    1012. We reject ISO/RTO Council and ISO-NE's request that we defer
our approval of Reliability Standards from the MOD group that
incorporate references to the 13 fill-in-the-blank standards. While we
understand ISO/RTO Council and ISO-NE's concern about cross-referencing
pending Reliability Standards, the data that is needed will be provided
as described in the Common Issues section.\322\ In the interim,
compliance with the pending Reliability Standards should continue on a
voluntary basis, and the Commission considers compliance with them a
matter of good utility practice. The Commission believes, moreover,
that the blanks will be filled in in a timely manner, since in this
rule we require the ERO to develop a Work Plan and submit a compliance
filing describing the process for collection of the information set
forth in the deferred standards.
---------------------------------------------------------------------------

    \322\ See Common Issues Pertaining to Reliability Standards:
Fill-in-the-Blank Standards, supra section II.E.5.
---------------------------------------------------------------------------

    1013. In response to EPSA's concern that opportunities for
discrimination and concerns about reliability remain while we await
additional information, we emphasize that the Commission has provided
specific direction regarding appropriate modifications to the MOD
standards here and in Order No. 890, and has required the submission of
a Work Plan for completion of that work within 90 days.\323\ Moreover,
the OATT and OASIS transparency reforms adopted in Order No. 890 will
ensure that opportunities for discrimination will be minimized while
NERC completes work on the MOD Reliability Standards.
---------------------------------------------------------------------------

    \323\ OATT Reform Final Rule, Order No. 890, issued February 15,
2007.
---------------------------------------------------------------------------

b. MOD Standards Related to ATC, TTC, CBM and TRM
i. OATT Reform and the MOD Standards
    1014. As pointed out in the NOPR, the Commission has been
considering ATC, TTC, CBM and TRM calculation issues in Docket Nos.
RM05-17-000 and RM05-25-000, and addressed them in Order No. 890. In
order to maintain a consistent approach with regard to ATC issues, we
confirm here the determinations made in Order No. 890. Each such
determination is addressed below.
    1015. In Order No. 890, the Commission addressed the potential for
undue discrimination by requiring industry-wide consistency and
transparency of all components of ATC calculation methodology and
certain definitions, data and modeling assumptions. The Commission also
indicated there that the lack of consistent, industry-wide ATC
calculation standards poses a threat to the reliable operation of the
Bulk-Power System, particularly with respect to the inability of one
transmission provider to know with certainty its neighbors' system
conditions affecting its own ATC values. As a result of this
reliability component, the Commission asserted that the proposed ATC
reforms are also supported by FPA section 215, through which the
Commission has the authority to direct the ERO to submit a Reliability
Standard that the Commission considers appropriate to implement FPA
section 215.\324\
---------------------------------------------------------------------------

    \324\ FPA section 215(d)(5).
---------------------------------------------------------------------------

    1016. In Order No. 890, the Commission directed public utilities,
working through NERC and NAESB, to develop Reliability Standards and
business practices to improve the consistency and transparency of ATC
calculations. The Commission required public utilities, working through
NERC, to modify the ATC-related Reliability Standards within 270 days
of publication of Order No. 890 in the Federal Register. The Commission
also directed public utilities to work through NAESB to develop
business practices that complement NERC's new Reliability Standards
within 360 days of publication of Order No. 890 in the Federal
Register. Finally, the Commission directed NERC and NAESB to file a
joint status report on standards and business practices development,
and a Work Plan for completion of this

[[Continued on page 16515]]

]

[[pp. 16515-16564]] Mandatory Reliability Standards for the Bulk-Power System

[[Continued from page 16514]]

task, within 90 days of publication of Order No. 890 in the Federal
Register.
    1017. The electric utility industry has also acknowledged this
problem and has taken steps to address the lack of consistency and
transparency in the way ATC is calculated. NERC formed a Long-Term
Available Flowgate Capacity Task Force to review NERC's standards on
ATC, which issued a final report in 2005.\325\ Based on the
recommendations in the NERC Report, NERC has begun two Standards
Authorization Request proceedings to revise the standards on ATC.\326\
NAESB has also begun a proceeding to develop business practice
standards to enhance the processing of transmission service requests
that affect ATC calculation. Following the issuance of the OATT Reform
NOPR on May 19, 2006, and the Reliability Standards NOPR on October 19,
2006, NERC accelerated development of these standards in accordance
with the guidelines provided in these NOPRs. NERC and NAESB
representatives participated in the Commission's Technical Conference
held on October 12, 2006, and informed the Commission on the status of
Reliability Standards development.\327\ NERC posted the Draft Standard
MOD-001-1, proposing ATC/TTC/AFC (Available Flowgate Capability)
revisions, on its Web site on February 15, 2007.\328\
---------------------------------------------------------------------------

    \325\ The NERC Report made recommendations for greater
consistency and greater clarity in the calculation of ATC/AFC. The
task force also recommended greater communication and coordination
of ATC/AFC information to ensure that neighboring entities exchange
relevant information. See NERC, Long-Term AFC/ATC Task Force Final
Report (2005) (NERC Report) at 2, available at: fttp://http://www.nerc.com/pub/sys/all_updl/mc/ltatf/LTATF_Final_Report_Revised.pdf
.

    \326\ The first SAR proceeding proposes changes to the existing
standards on ATC to, among other things, further establish
consistency in the calculation of ATC and to increase the clarity of
each transmission provider's ATC calculation methodology. The second
SAR proceeding proposes certain changes to NERC's existing CBM and
TRM standards and calls for greater regional consistency and
transparency in how CBM and TRM are treated in transmission
providers' ATC calculations.
    \327\ Technical Conference regarding Preventing Undue
Discrimination and Preference in Transmission Service under RM05-25
et al. (October 12, 2006).
    \328\ That posting preceded by one day the issuance of Order No.
890. Therefore, the posted draft Standard MOD-001-1 does not reflect
the requirements of Order No. 890, but rather is guided by the NOPR
issued in the OATT Reform and Reliability Standards proceedings.
---------------------------------------------------------------------------

(a) Comments
    1018. EPSA commends the Commission for recognizing the direct
connection between the MOD group of Reliability Standards and the
initiative to reform Order No. 888 to address existing opportunities to
discriminate against competitive power suppliers in access to the
transmission system. TAPS and EPSA note that in both the OATT Reform
NOPR and the Reliability Standards NOPR, the Commission has articulated
serious concerns about the lack of clarity, transparency and uniformity
in the critical calculations pertaining to one of the most fundamental
aspects of the wholesale bulk power transmission system, and urge the
Commission to make these calculations transparent, consistent, and
better yet, regional. TAPS agrees with Staff's concerns raised in the
NOPR about ATC, TTC, CBM and TRM standards. Constellation particularly
supports the proposed changes to MOD-001-0, MOD-004-0, MOD-006-0 and
MOD-007-0 because these Reliability Standards, as modified, will
provide more information to users regarding ATC, TTC, existing
transmission commitments (ETC), AFC, CBM and TRM, and that information
will begin the process of providing consistent standards for their
calculation.
    1019. Constellation agrees with EPSA and cautions that it will take
time for NERC to develop, and for the Commission to definitively
approve, ATC-related standards. Constellation therefore proposes that
the Commission should, upon issuance of a Final Rule, require
transmission providers to post the information that the Commission
directs regarding these values, even if work toward more consistency is
not yet complete. Constellation believes that this will aid in ensuring
that users request and receive more reliable transmission service on a
nondiscriminatory basis.
    1020. Contrary to the majority of commenters that support
Commission action regarding ATC issues, MISO states that a Reliability
Standard is not the place to address perceived comparability issues.
MISO states that NERC is responsible for Reliability Standards, but not
for tariffs and business practices that deal with market and equity
issues.
(b) Commission Determination
    1021. We agree with the many commenters that recognize the direct
connection between the MOD group of Reliability Standards and available
transfer capability methodologies addressed in Order No. 890, in which
we developed policies to lessen, if not fully eliminate, opportunities
to discriminate against competitive power suppliers in access to the
transmission system.
    1022. We recognize the concerns raised by EPSA and Constellation
that opportunities for discrimination and related reliability concerns
may remain during the interim Reliability Standards modification
process, in part because of the discretion that transmission service
providers will retain in calculating ATC values. We point out, however,
that all transmission providers are required to file a modified
Attachment C to their OATTs detailing their ATC calculation
methodologies in advance of the development of the new Reliability
Standards. All transmission providers are required to comply with their
OATTs, and are subject to the filing of a complaint or Commission-
initiated enforcement action if discrimination occurs. Regarding
Constellation's recommendation that the Commission act in advance, and
require transmission service providers to post the information that the
Commission directs regarding ATC values, even if work toward more
consistency is not yet complete, we clarify that we will require
transmission service providers to comply with existing ATC-related
posting obligations on OASIS as supplemented by Order No. 890. These
requirements are not subject to standardization by the ERO, and will be
effective in accordance with the timeline stated in Order No. 890.
    1023. We disagree with MISO's contention that the Reliability
Standards are an inappropriate venue for addressing ATC comparability
issues. ATC raises both comparability and reliability issues, and it
would be irresponsible to take action under FPA section 206 to require
consistency in ATC calculations without considering the reliability
impact of those decisions. Therefore, the Commission in Order No. 890
provided direction to public utilities, working through NERC and NAESB,
regarding development of the ATC-related Reliability Standards and
business practices, and we repeat that direction here.
c. Documentation of Total Transfer Capability and Available Transfer
Capability Calculation Methodologies (MOD-001-0)
    1024. The purpose of MOD-001-0 is to promote the consistent and
uniform application of transfer capability calculations among
transmission system users. The Reliability Standard requires each
regional reliability organization to develop a regional TTC and ATC
methodology in conjunction with its members and to post the most recent
version of its TTC and ATC methodologies on a Web site accessible by
NERC, the regional reliability organization, and transmission users.
    1025. In the NOPR, the Commission identified MOD-001-0 as a fill-
in-the-

blank standard that requires each regional reliability organization to
develop its respective methods for determining TTC and ATC and to make
those methodologies available to others for review. The NOPR stated
that the Commission would not propose to approve or remand MOD-001-0
until the ERO submits additional information.
    1026. Although the Commission did not propose any action with
regard to MOD-001-0, it addressed a number of concerns regarding the
Reliability Standard, consistent with those proposed in the OATT Reform
NOPR. The Commission proposed that this standard should: (1) At a
minimum, provide a framework for ATC, TTC and ETC calculation; (2)
require disclosure of algorithms and processes used in ATC calculation;
(3) identify a detailed list of information to be exchanged among
transmission providers for the purposes of ATC modeling; (4) include
requirements that the assumptions used in ATC and AFC calculations be
consistent with those used for planning expansion or operation of the
Bulk-Power System to the maximum extent practicable; \329\ (5) include
a requirement that applicable entities make available assumptions and
contingencies underlying ATC and TTC calculations; (6) address only ATC
while the TTC should be addressed under FAC-012-1; and (7) identify to
whom MOD-001-0 standards apply, i.e., users, owners and operators of
the Bulk-Power System.\330\ We will discuss the comments and Commission
conclusions for each of these modifications separately below.
---------------------------------------------------------------------------

    \329\ NOPR at P 609.
    \330\ Id. at P 610. We note that our observation regarding
applicable entities here also applies to MOD-002-0, MOD-003-0, MOD-
004-0, MOD-005-0, MOD-008-0, MOD-009-0, MOD-011-0, MOD-013-0, MOD-
014-0, MOD-015-0, MOD-016-0, MOD-024-0 and MOD-025-0.
---------------------------------------------------------------------------

i. Comments
    1027. APPA agrees with the Commission that MOD-001-0 in its current
form is a fill-in-the-blank standard, is not sufficient in its current
form and should not be accepted for approval as a mandatory Reliability
Standard until the accompanying regional procedures are submitted and
approved.
ii. Commission Determination
    1028. The Commission adopts the NOPR proposal not to approve or
remand MOD-001-0 until the ERO submits additional information.
Consistent with Order No. 890, and comments received in response to the
NOPR, the Commission directs the ERO to consider modifications of MOD-
001-0 through the Reliability Standards development process as
discussed below.
iii. Provide a Framework for ATC, TTC and ETC Calculation
(a) Comments
    1029. APPA supports the Commission's proposal that NERC modify MOD-
001-0 to, at a minimum, provide a framework for ATC, TTC and ETC
calculation.
(b) Commission Determination
    1030. We continue to believe that MOD-001-0 should, at a minimum,
provide a framework for ATC, TTC and ETC calculations. This framework
should consider industry-wide consistency of all ATC components and
certain data inputs and exchange, modeling assumptions, calculation
frequency, and coordination of data relevant for the calculation of
ATC. Consistent with Order No. 890, we do not require a single
computational process for calculating ATC for several reasons. First,
it is not our intent to require transmission providers to incur the
expense of developing and adopting a new one-size-fits-all software
package to calculate ATC without proven benefits. More importantly, we
find that the potential for discrimination and decline in reliability
level does not lie primarily in the choice of an ATC calculation
methodology, but rather in the consistent application of its
components, and input and exchange data, along with modeling
assumptions. Consistent and transparent ATC calculation will provide
equivalent results between regions and will therefore prevent
transmission service providers from overselling transfer capability
that can stress conditions on their own and adjacent systems, and
jeopardize reliability. In addition, we are especially concerned with
the lack of data exchange between neighboring transmission service
providers, which is a prerequisite for accurate calculation of ATC.
    1031. The Commission understands that the ERO currently is
developing three ATC calculation methodologies (contract or rating path
ATC, network ATC, and network AFC).\331\ If all of the ATC components,
and certain data inputs and assumptions are consistent, the three ATC
calculation methodologies will produce predictable and sufficiently
accurate, consistent, equivalent and replicable results. It is
therefore not necessary to require a single industry-wide ATC
calculation methodology.
---------------------------------------------------------------------------

    \331\ October 12, 2006 Technical Conference regarding Preventing
Undue Discrimination and Preference in Transmission Service under
RM05-25 et al. These three methodologies are different computational
processes to determine a transmission system's ATC. The first,
contract path, examines TTC for every A-to-B path on the system in
concert with all others, reduces ATC by path for ETC, TRM and CBM,
as appropriate, and produces ATC for each path. The second method,
network ATC, uses a simulator to look not at each path, but at each
transmission element (line, substation, etc.) and run first
contingency simulations to establish ATC on a network basis, rather
than a path basis. The third method, network AFC, uses a simulator
to examine critical flowgates over a wider area, then requires a
second step to convert AFC values to particular path ATC values.
---------------------------------------------------------------------------

    1032. In addition, consistent with Order No. 890, we note that
there is neither a definition of AFC/TFC (Total Flowgate Capability) in
the ERO's glossary nor an existing Reliability Standard that discusses
AFC. Consistent with our approach to achieving consistency and
transparency, we direct the ERO to develop AFC/TFC definitions and
requirements used to identify a particular set of transmission
facilities as flowgates. We extend the same requirements for industry-
wide consistency of all AFC components and certain data inputs and
exchange, modeling assumptions, calculation frequency, and coordination
of data relevant for the calculation of AFC as we stated above for ATC.
However, we remind transmission providers that our regulations require
the posting of ATC values associated with a particular path, not AFC
values associated with a flowgate. Accordingly, transmission providers
using an AFC methodology must convert flowgate (AFC) values into path
(ATC) values for OASIS posting. In order to display consistent posting
of ATC and TTC values on OASIS, we direct the ERO to develop a
Requirement in the Reliability Standard for conversion of AFC into ATC
values for use by transmission providers that currently apply flowgate
methodology.
    1033. We underscore Order No. 890's objective of greater
consistency in ETC calculations. The Commission directs the ERO to
develop a consistent approach for determining the amount of transfer
capability a transmission provider may set aside for its native load
and other committed uses. We expect that the ERO will address ETC
through the MOD-001-0 Reliability Standard rather than through a
separate Reliability Standard. By using MOD-001-0, the ETC calculation
principles can be adjusted to apply to each of the three ATC
methodologies being developed by the ERO. In order to provide specific
direction to public utilities and the ERO, we determine that

ETC should be defined to include committed uses of the transmission
system, including: (1) Native load commitments (including network
service); (2) grandfathered transmission rights; (3) firm and non-firm
point-to-point reservations; (4) rollover rights associated with long-
term firm service and (5) other uses identified through the ERO
process. ETC should not be used to set aside transfer capability for
any type of planning or contingency reserve; these are to be addressed
through CBM and TRM.\332\ In addition, in the short-term ATC
calculation, all reserved but unused transfer capability (non-
scheduled) must be released as non-firm ATC.
---------------------------------------------------------------------------

    \332\ TRM also includes such things as loop flow and parallel
path flow.
---------------------------------------------------------------------------

    1034. We reiterate the finding in Order No. 890 that including all
requests for transmission service in ETC is likely to overstate usage
of the system and understate ATC. Accordingly, we find that
reservations that have the same point of receipt (POR) (generator) but
different point of delivery (POD) (load), for the same time frame,
should not be modeled in the ETC calculation simultaneously if their
combined reserved transmission capacity exceeds the generator's
nameplate capacity at a POR. This will prevent unrealistic use of
transmission capacity associated with power output from a generator
identified as a POR. One approach that could be used is examining
historical patterns of actual reservation use during a particular
season, month, or time of day.
    1035. In summary, we direct the ERO to modify MOD-001-0 to provide
a framework for ATC, TTC and ETC calculation that, consistent with the
discussion above: (1) Requires industry-wide consistency of all ATC
components and certain data inputs and exchange, modeling assumptions,
calculation frequency, and coordination of data relevant for the
calculation of ATC; (2) provides predictable and sufficiently accurate,
consistent, equivalent, and replicable ATC calculations regardless of
the methodology used by the region; (3) provides the definition of AFC
and method for its conversion to ATC; (4) lays out clear instructions
on how ETC should be defined and (5) identifies to whom MOD-001-0
Reliability Standards apply, i.e., users, owners and operators of the
Bulk-Power System.
iv. Require Disclosure of Algorithms and Processes Used in ATC
Calculation
(a) Comments
    1036. APPA supports the Commission's proposal that NERC modify MOD-
001-0 to require documentation including mathematical algorithms,
process flow diagrams, data inputs and identification of flowgates.
(b) Commission Determination
    1037. The Commission adopts the proposal from the NOPR to direct
the ERO to modify Reliability Standard MOD-001-0 to require disclosure
of the algorithms and processes used in ATC calculation. In addition,
consistent with Order No. 890, the Commission believes that further
clarification is necessary regarding the ATC calculation algorithm for
firm and non-firm ATC.\333\ Currently, the ERO has no specifications
for calculating non-firm ATC. We find that the same potential for
discrimination exists for non-firm transmission service as for firm
service, and greater uniformity in both firm and non-firm ATC
calculations will substantially reduce the remaining potential for
undue discrimination. Therefore, we direct the ERO to modify
Reliability Standard MOD-001-0 to require disclosure of the algorithms
and processes used in ATC calculation, and also to implement the
following principles for firm and non-firm ATC calculations: (1) For
firm ATC calculations, the transmission provider shall account only for
firm commitments and (2) for non-firm ATC calculations, the
transmission provider shall account for both firm and non-firm
commitments, postbacks of redirected service, unscheduled service and
counterflows.
---------------------------------------------------------------------------

    \333\ The NERC ATC definition does not differentiate firm and
non-firm ATC from the following high level generic ATC definition: 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
less existing transmission commitments (including retail customer
service), less a Capacity Benefit Margin, less a Transmission
Reliability Margin.
---------------------------------------------------------------------------

v. Identify a Detailed List of Information To Be Exchanged Among
Transmission Providers for the Purposes of ATC Modeling
(a) Comments
    1038. APPA supports the Commission's proposal that NERC modify MOD-
001-0 to require applicable entities to identify a detailed list of
information to be shared.
(b) Commission Determination
    1039. The Commission adopts the NOPR proposal and reiterates the
requirement in Order No. 890 that the ERO must revise the MOD
Reliability Standards to require the exchange of data and coordination
among transmission providers. We direct the ERO to modify MOD-001-0 to
ensure that the following data, at a minimum, be exchanged among
transmission providers for the purposes of ATC modeling: (1) Load
levels; (2) transmission planned and contingency outages; (3)
generation planned and contingency outages; (4) base generation
dispatch; (5) existing transmission reservations, including
counterflows; (6) ATC recalculation frequency and times and (7) source/
sink modeling identification.\334\ The Commission concludes that the
exchange of such data is necessary to support the reforms requiring
consistency in the determination of ATC adopted in this Final Rule. As
explained above, transmission providers are required to coordinate the
calculation of TTC/TFC and ATC/AFC with others, and this requires a
standard means of exchanging data.
---------------------------------------------------------------------------

    \334\ NOPR at P 169.
---------------------------------------------------------------------------

vi. Include Requirements That the Assumptions Used in ATC and AFC
Calculations Should Be Consistent, to the Maximum Extent Practicable,
With Those Used for Planning the Expansion or Operation of the Bulk-
Power System
(a) Commission Determination
    1040. The Commission adopts the NOPR's proposal to require
transmission providers to use data and modeling assumptions for short-
and long-term ATC calculations that are consistent with those used for
the planning of operations and system expansion, to the maximum extent
practicable. This includes, for example: (1) Load levels; (2)
generation dispatch; (3) transmission and generation facilities
maintenance schedules; (4) contingency outages; (5) topology; (6)
transmission reservations; (7) assumptions regarding transmission and
generation facility additions and retirements and (8) counterflows,
which must be the same in the models used in the transmission
operational and planning studies performed for the transmission
providers' native load. We find that requiring consistency in the data
and modeling assumptions used for ATC calculation will remedy the
potential for undue discrimination by eliminating discretion and
ensuring comparability in the manner in which a

transmission provider operates and plans its system to serve native
load, and the manner in which it calculates ATC for service to third
parties.
    1041. We clarify that we require consistent use of assumptions
underlying operational planning for short-term ATC and expansion
planning for long-term ATC calculation. We also clarify that there must
be a consistent basis for or approach to determining load levels in
each of these sets of calculations. For example, one approach may be
for transmission providers to calculate load levels using an on- and
off-peak model for each month when evaluating yearly service requests
and calculating yearly ATC. The same (peak- and off-peak) or
alternative approaches may be used for monthly, weekly, daily and
hourly ATC calculations. Regardless of the ultimate choice, it is
imperative that all transmission providers use the same approach to
modeling load levels to eliminate undue discrimination and enable the
meaningful exchange of data among transmission providers. Accordingly,
we direct the ERO to develop consistent requirements for modeling load
levels in MOD-001-0.
    1042. With respect to modeling of generation dispatch, we direct
the ERO to develop requirements in MOD-001-0 specifying how
transmission providers should determine which generators should be
modeled in service, including guidance on how independent generation
should be considered. Accordingly, we direct the ERO to revise
Reliability Standard MOD-001-0 by specifying that base generation
dispatch will model: (1) All designated network resources and other
resources that are committed to or have the legal obligation to run, as
they are expected to run and (2) all uncommitted resources that are
deliverable within the control area, economically dispatched as
necessary to meet balancing requirements.
    1043. Regarding transmission reservations modeling, we direct the
ERO to develop requirements in Reliability Standard MOD-001-0 that
specify: (1) A consistent approach on how to simulate reservations from
points of receipt to points of delivery when sources and sinks are
unknown and (2) how to model existing reservations.
    1044. Consistent with Order No. 890, the Commission directs the ERO
to modify Reliability Standard MOD-001-0 to require ATC to be updated
by all transmission providers on a consistent time interval and in a
manner that closely reflects the actual topology of the system, e.g.,
generation and transmission outages, load forecasts, interchange
schedules, transmission reservations, facility ratings and other
necessary data. This process must also consider whether ATC should be
calculated more frequently for constrained facilities.
    1045. In conclusion, we direct the ERO to modify MOD-001-0 to
require that: (1) Assumptions used for short-term ATC calculations be
consistent with those used for operation planning to the maximum extent
practicable; (2) assumptions used for long-term ATC calculations be
consistent with those used for system planning to the maximum extent
practicable and (3) ATC be updated by all transmission providers on a
consistent time interval.
vii. Include a Requirement That Applicable Entities Make Available
Assumptions and Contingencies Underlying ATC and TTC Calculations
(a) Comments
    1046. APPA supports the Commission's proposal that NERC modify MOD-
001-0 to include a requirement that applicable entities make available
a comprehensive list of assumptions and contingencies underlying ATC
and TTC calculations.
(b) Commission Determination
    1047. We adopt the NOPR's proposal that this Reliability Standard
should include a requirement that applicable entities make available a
comprehensive list of assumptions and contingencies underlying ATC/AFC
and TTC/TFC calculations. While we require the submission of
contingency files under MOD-010-0, here we only direct the ERO to
consider development of a requirement that the transmission service
provider declare what type of contingencies it uses for specific
calculations of ATC/AFC and TTC/TFC, and release the contingency files
upon request if not submitted with the data filed with the ERO in
compliance with MOD-010-0.
    1048. In order to increase the transparency of ATC calculations, we
adopt the NOPR's proposal and direct the ERO to develop in MOD-001-0 a
requirement that each transmission service provider provide on OASIS
its OATT Attachment C, in which Order No. 890 requires transmission
providers to include a detailed description of the specific
mathematical algorithm the transmission provider uses to calculate both
firm and non-firm ATC for various time frames such as: (1) The
scheduling horizon (same day and real-time), (2) operating horizon (day
ahead and pre-schedule) and (3) planning horizon (beyond the operating
horizon). In addition, a transmission provider must include a process
flow diagram that describes the various steps that it takes in
performing the ATC calculation.
viii. Address Only ATC While TTC Should Be Addressed Under FAC-012-1
(a) Comments
    1049. APPA concurs with the NOPR's proposal that TTC should be
standardized under FAC-012-1, and that there appears to be little or no
distinction between the definitions for TTC (MOD-001-0) and TC (FAC-
012-1). APPA anticipates that this distinction will either be clarified
or eliminated through ongoing Reliability Standards development
activity.
    1050. Conversely, MidAmerican notes that the transfer capability
covered by FAC-012-1 may not relate to the TTC that is the subject of
the MOD-001-0 standard. MidAmerican opines that the purpose of the FAC-
012-1 standard is to ensure that each reliability coordinator and
planning authority documents the methodology used to develop inter- and
intra-regional transfer capabilities used in the reliable planning and
operation of the Bulk-Electric System. MidAmerican further details that
transfer capabilities that are covered by FAC-012-1 could be used by a
reliability coordinator to operate the system in a temporary situation
or by the planning authority as the basis for a sensitivity case. It
adds that in neither of these cases would these transfer capabilities
necessarily be included in calculations for ATC that would be used for
offering transmission capacity for sale.
(b) Commission Determination
    1051. We adopt the NOPR proposal and require that TTC be addressed
under the Reliability Standard that deals with transfer capability such
as FAC-012-1, rather than MOD-001-0. The FAC series of standards
contain the Reliability Standards that form the technical and
procedural basis for calculating transfer capabilities. FAC-008-1
provides the basis for determining the thermal ratings of facilities
while FAC-009-1 provides the basis for communicating those ratings.
FAC-010-1 and FAC-011-1 provide the system operating limits
methodologies for the planning and operational horizon respectively and
FAC-014 provides for the communication of those ratings.\335\
---------------------------------------------------------------------------

    \335\ FAC-010, FAC-011, and FAC-014 are addressed in Docket No.
RM07-03 because they were submitted later than the original 107
Reliability Standards and we did not have sufficient time to allow
appropriate review and comment.

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

    1052. The Commission directs the ERO, through the Reliability
Standards development process, to modify FAC-012-1 and any other
appropriate Reliability Standards to assure consistency in the
determination of TTC/TFC for services provided under the pro forma
OATT, and requires that those processes be the same as those used in
operation and planning for native load and reliability assessment
studies. Changes to the process of calculating TTC are appropriate if
implementation is coordinated with revisions to the other applicable
operating or planning standards. We acknowledge that reliability
regions have historically calculated transfer capability using
different approaches, and we agree that regional differences should be
respected.\336\ However, as already discussed above regarding ATC, TTC
requirements will be determined in the ERO Reliability Standards
development process, and any request for a regional difference from the
Reliability Standards must take place through the ERO process.
---------------------------------------------------------------------------

    \336\ For example, WECC has a documented open process for
establishing TTC for the Western Interconnection.
---------------------------------------------------------------------------

    1053. We disagree with MidAmerican's opinion that transfer
capabilities that are addressed by FAC-012-1 are necessarily different
from TTC used for ATC calculation. The NERC glossary defines transfer
capability (TC) \337\ as essentially identical to TTC.\338\ We believe
that modeling principles for simulating power transfers and
determination of transfer capabilities should be the subject of a
single standard. Those principles should be the same regardless of
whether transfer capability is used for the purpose of operations,
planning or offering for sale. By modeling principles we refer to the
way transfers are simulated and the type of analysis that should be
performed, such as steady-state, dynamic stability or voltage
stability. We are certain that consistent calculation of transfer
capabilities will prevent over- and under-estimation of the total
transfer capability available for sale. We agree with APPA that this
distinction should either be clarified or eliminated through the
ongoing Reliability Standards development process, and therefore direct
the ERO to modify MOD-001-0 to address TTC under transfer capability-
related standards such as the FAC group of Reliability Standards.
---------------------------------------------------------------------------

    \337\ Transfer Capability is defined in the NERC glossary as
``[t]he measure of the ability of interconnected electric systems to
move or transfer power in a reliable manner from one area to another
over all transmission lines (or paths) between those areas under
specified system conditions. The units of transfer capability are in
terms of electric power, generally expressed in megawatts (MW). The
transfer capability from `Area A' to `Area B' is not generally equal
to the transfer capability from `Area B' to `Area A.' '' NERC
Glossary at 18.
    \338\ Total Transfer Capability is defined in the NERC glossary
as ``[t]he amount of electric power that can be moved or transferred
reliably from one area to another area of the interconnected
transmission systems by way of all transmission lines (or paths)
between those areas under specified system conditions.'' Id.
---------------------------------------------------------------------------

ix. Identify the Entities To Whom the MOD Standards Apply
(a) Comments
    1054. APPA agrees in part with the Commission's conclusion that
``NERC should identify the applicable entities in terms of users,
owners and operators of the Bulk-Power Systems.'' \339\ APPA, however,
is concerned that this approach may confuse rather than clarify
compliance responsibilities. According to APPA, a regional organization
in conjunction with entities that plan, own, operate (and use)
transmission facilities within each region must be involved in the
development of any regional TTC and ATC methodology. In this context,
APPA views the ``regional reliability organization'' as the technical
arm of the reliability region, made up of the various committees whose
members are users, owners and operators of the Bulk-Power System, along
with support from the regional reliability organization staff. Further,
APPA notes that ultimately, it is these core users, owners and
operators of the Bulk-Power System that are responsible for the
development of and adherence to the ATC methodology, and that the
regional reliability organization, as an organization, is responsible
for ensuring that the methodology is developed (under R1) and publicly
posted (under R2).
---------------------------------------------------------------------------

    \339\ NOPR at P 610.
---------------------------------------------------------------------------

    1055. In addition, APPA states that under the statutory framework
established in FPA section 215, as interpreted by the Commission in
Order No. 672, it is clear that the compliance monitor within each
region is the Regional Entity, and the Regional Entity is not a user,
owner or operator of the Bulk-Power System. APPA notes that while
regional delegation agreements may be used to impose certain
reliability compliance functions upon Regional Entities and their
affiliates, no Regional Entity should be charged with enforcing
compliance against itself. Ultimately, APPA is concerned that the
quality of regional modeling and technical assessments will be
diminished if the collaborative efforts used for the past 50 years of
interconnected operations are displaced due to pressures to identify a
single entity or class of entities with direct compliance
responsibilities for regional modeling standards. APPA states that
identifying all users, owners and operators as responsible entities
does not answer the question either. APPA expresses its intention that
it will work with NERC and with other stakeholders to ensure that this
industry-based expertise is maintained and enhanced, while ensuring
that responsible entities are identified in this and other NERC
standards.
(b) Commission Determination
    1056. APPA is suggesting that respective regional organizations,
their technical staff, and committees of users, owners and operators of
the Bulk-Power System be charged with developing the methodologies. We
disagree. These Reliability Standards should be developed through the
Commission-approved Reliability Standards development process which
will identify the entities that should implement the Reliability
Standards, the Requirements necessary to achieve the goals identified
in Order No. 890, and the Measures necessary to monitor compliance.
    1057. The Commission agrees with APPA that the collaborative
efforts and knowledge developed over decades of interconnected
operation should not be wasted. We do not believe that will happen
through the Reliability Standards development process and that all of
the applicable entities will have significant roles to play in
achieving the goal the Commission has set out in Order No. 890.
Therefore, we adopt the proposal in the NOPR and direct the ERO to
modify MOD-001-0 to reflect the users, owners and operators to which
the Reliability Standard will apply.
x. Summary of Commission Determination
    1058. Accordingly, the Commission neither accepts nor remands MOD-
001-0 until the ERO submits additional information. Although the
Commission does not propose any action with regard to MOD-001-0, we
address above a number of concerns regarding the Reliability Standard,
consistent with those set forth in Order No. 890. We direct the ERO to
develop modifications to the Reliability Standard through the
Reliability Standards development process that: (1) Provide a framework
for ATC, TTC and ETC calculation,

developing industry-wide consistency of all ATC components; (2) require
disclosure of algorithms, for both firm and non-firm ATC and processes
used in the ATC calculation; (3) identify a detailed list of
information to be exchanged among transmission providers for the
purposes of ATC modeling; (4) include a requirement that the
assumptions used in ATC and AFC calculations should be consistent with
those used for planning the expansion or operation of the Bulk-Power
System to the maximum extent practicable; (5) include a requirement
that ATC be updated by all transmission providers on a consistent time
interval; (6) include a requirement that applicable entities make
available assumptions and contingencies underlying ATC and TTC
calculations; (7) address only ATC/AFC while TTC/TFC should be
addressed under transfer capability standards such as FAC-012-1 and (8)
identify the applicable entities in terms of users, owners and
operators of the Bulk-Power System.
d. Review of Transmission Service Provider Total Transfer Capability
and Available Transfer Capability Calculations and Results (MOD-002-0)
    1059. MOD-002-0 concerns the review of transmission service
providers' compliance with the regional methodologies for calculating
TTC and ATC. It requires that the regional reliability organization:
(1) Develop and implement a procedure to periodically review and ensure
that the TTC and ATC calculations and resulting values developed by
transmission service providers comply with the regional TTC and ATC
methodology and applicable regional criteria; (2) document the results
of its periodic review and (3) provide the results of its most current
reviews to NERC upon request.
    1060. In the NOPR, the Commission identified MOD-002-0 as a fill-
in-the-blank standard that requires each regional reliability
organization to develop and implement a procedure to periodically
review and ensure that a transmission service provider's TTC and ATC
calculations comply with regional TTC and ATC methodologies and
criteria. The NOPR stated that the Commission would not propose to
approve or remand MOD-002-0 until the ERO submits additional
information.
i. Comments
    1061. APPA agrees that MOD-002-0 is a fill-in-the-blank standard.
It is not sufficient in its current form and should not be approved as
a mandatory Reliability Standard until the accompanying regional
procedures are submitted and approved.
ii. Commission Determination
    1062. The Commission adopts the NOPR proposal not to approve or
remand MOD-002-0 until the ERO submits additional information. Because
the regional procedures have not been submitted to the Commission, it
is not possible to determine at this time whether MOD-002-0 satisfies
the statutory requirement that a proposed Reliability Standard be
``just, reasonable, not unduly discriminatory or preferential, and in
the public interest.'' Accordingly, the Commission neither approves nor
remands this Reliability Standard until the regional procedures are
submitted. In the interim, compliance with MOD-002-0 should continue on
a voluntary basis, and the Commission considers compliance with the
Reliability Standard to be a matter of good utility practice.
e. Regional Procedure for Input on Total Transfer Capability and
Available Transfer Capability Methodologies and Values (MOD-003-0)
    1063. MOD-003-0 requires each regional reliability organization to:
(1) Develop and document a procedure on how a transmission user can
present its concerns or questions regarding TTC and ATC calculations
including the TTC and ATC values, and how these concerns will be
addressed and (2) make its procedure for receiving and addressing these
concerns available to other regional reliability organizations, NERC
and transmission users on its Web site.
    1064. In the NOPR, the Commission identified MOD-003-0 as a fill-
in-the-blank standard that requires each regional reliability
organization to develop and document a procedure on how a transmission
user can present its concerns regarding the TTC and ATC methodologies
of a transmission service provider. The NOPR stated that the Commission
would not propose to approve or remand MOD-003-0 until the ERO submits
additional information.
i. Comments
    1065. APPA agrees that MOD-003-0 is a fill-in-the-blank standard.
It notes that it is not sufficient in its current form and should not
be approved as a mandatory Reliability Standard until the accompanying
regional procedures are submitted and approved. In addition, APPA hopes
that if NERC develops the MOD-001-0 Reliability Standard properly, it
will include a reporting procedure for addressing shortcomings in
information for all transmission customers (LSE, generator owner and
purchasing-selling entity) in the MOD-001-0 Standard. APPA argues that,
as a result, MOD-003-0 may be redundant and should be eliminated.
ii. Commission Determination
    1066. The Commission adopts the NOPR proposal not to approve or
remand MOD-003-0 until the ERO submits additional information. Because
the regional procedures have not been submitted to the Commission, it
is not possible to determine at this time whether MOD-003-0 satisfies
the statutory requirement that a proposed Reliability Standard be
``just, reasonable, not unduly discriminatory or preferential, and in
the public interest.'' Accordingly, the Commission neither accepts nor
remands this Reliability Standard until the regional procedures are
submitted. In the interim, compliance with MOD-003-0 should continue on
a voluntary basis, and the Commission considers compliance with the
Reliability Standard to be a matter of good utility practice.
    1067. We direct the ERO to consider APPA's suggestion that MOD-003-
0 may be redundant and should be eliminated if the ERO develops a
modification to the MOD-001-0 Reliability Standard through the
Reliability Standards development process that includes reporting
requirements.
f. Documentation of Regional Reliability Organization Capacity Benefit
Margin Methodologies (MOD-004-0)
    1068. MOD-004-0 requires each regional reliability organization to:
(1) Develop and document a regional CBM \340\ methodology in
conjunction with its members and (2) post the most recent version of
its CBM methodology on a Web site accessible by NERC, regional
reliability organizations and transmission users.
---------------------------------------------------------------------------

    \340\ The NERC glossary defines ``capacity benefit margin'' or
``CBM'' as the amount of firm transmission transfer capability
preserved by a transmission provider for load serving entities whose
loads are located on the transmission service provider's system, to
enable access by the load serving entity to generation from
interconnected systems to meet generation reliability requirements.
NERC Glossary at 2.
---------------------------------------------------------------------------

    1069. In the NOPR, the Commission identified MOD-004-0 as a fill-
in-the-blank standard that requires each regional reliability
organization to develop and document a regional CBM methodology. The
NOPR stated that because the regional CBM methodologies had not been
submitted, the Commission would not propose to

approve or remand MOD-004-0 until the ERO submits the additional
information.
    1070. Although not proposing any action, the Commission nonetheless
indicated that MOD-004-0 could be improved by: (1) Providing more
specific requirements on how CBM should be determined and allocated to
interfaces and (2) including a provision ensuring that CBM, TRM and ETC
cannot be used for the same purpose, such as the loss of an identical
generation unit. Further, the Commission expressed concern that the
Reliability Standard may unduly impact competition because of the lack
of consistent criteria and clarity with regard to the entity on whose
behalf CBM has been set aside. This lack of consistent criteria has the
potential to result in the transmission provider's setting aside
capacity that it might not otherwise need to set aside, thus increasing
costs for native load customers and blocking third party uses of the
transmission system.
i. Comments
    1071. APPA agrees with the Commission that MOD-004-0 should not be
approved as a mandatory Reliability Standard until the relevant
regional procedures are submitted and approved.\341\
---------------------------------------------------------------------------

    \341\ APPA notes that it has expressed its own concerns with CBM
calculations and set-asides in its August 7, 2006 Initial Comments
filed in Docket No. RM05-25-000, at 31-55. APPA is hopeful these
concerns can be addressed through NERC's Reliability Standards
development process.
---------------------------------------------------------------------------

    1072. FirstEnergy states that transmission capacity margins such as
CBM and TRM are vitally important to the reliability of the system, and
any methodology that would unduly limit these margins could create a
danger of limiting transmission capacity over interconnected facilities
that would limit the ability of balancing authorities and others to
obtain generation reserves needed from the grid during contingency
events. In contrast, TAPS questions how TRM or, especially, CBM, can be
viewed as Reliability Standards if they are optional for the
transmission provider.
    1073. MidAmerican supports greater uniformity of CBM definitions
and calculations and states that the revised standard and/or new
standards should support transparency and uniformity by encouraging
increased availability of information and consistent data input and
modeling assumptions. EEI emphasizes that additional data and
information-sharing requirements would improve the transparency of
various calculations and assumptions related to CBM, including this
standard and the other CBM-related standards. EEI believes that,
similar to the peer review processes of the planning studies carried
out under the TPL standards, industry participants are best suited to
developing the totality of assumptions, system conditions and other
input variables that support the calculations.
    1074. EEI notes that, with respect to the Commission's particular
concern about criteria in determining resources and loads used in the
CBM methodology, NERC's ``ATC Definitions and Determination'' \342\
document clearly delineates the purpose and intent of the calculation
of CBM and TRM. EEI states that CBM is intended to provide generation
reliability, and TRM is intended to provide transmission reliability.
EEI believes that, to the extent capacity capable of supplying CBM is
located in the vicinity of the designated facility experiencing an
outage, transmission may or may not be available under the native load
reservation normally used for the facility. Therefore, EEI argues, CBM
may be needed on an interface where capacity is available for use as
CBM, and not allowing all generation to be considered in this manner
may unduly increase the generation reserve requirement within the
transmission provider's system.
---------------------------------------------------------------------------

    \342\ NERC, Available Transfer Capability Definitions and
Determination--A Framework for Determining Available Transfer
Capabilities of the Interconnected Transmission Networks for a
Commercially Viable Electricity Market (June 1996).
---------------------------------------------------------------------------

    1075. EEI agrees with the Commission's concern about double-
counting TRM for those transmission providers who do not opt to use
CBM. However, EEI argues that for transmission providers who do opt to
use CBM, it may be appropriate in some circumstances to use the same
generation unit outage to determine the impact on both generation and
transmission reliability because the impacts are different. EEI
cautions that artificially restricting such use is not appropriate,
especially before NERC's development of TRM and CBM standards and their
presentation to FERC through the Reliability Standards development
process. EEI recommends that the Commission encourage transmission
providers to make CBM and TRM capacity available to wholesale markets
for purchase on a non-firm basis, because doing so would ensure that
both CBM and TRM capacity are available to the transmission provider
during system emergencies, as intended. EEI notes that at other times
the transfer capability associated with TRM and CBM would be available
to the market, alleviating the concern of possible double-counting.
MidAmerican also supports the Commission's conclusion that double-
counting would be inappropriate, although MidAmerican states that it is
not aware of any cases of double-counting of margins.
    1076. TAPS notes the significant potential for abuse \343\ that
could result from the current flexibility afforded transmission
providers in the calculation of CBM and TRM, and proposes innovative
approaches \344\ to take CBM and (to the extent it is intended to cover
transmission required for reserve sharing) TRM out of the hands of
individual transmission providers, and to therefore reduce the
opportunity for abuse.
---------------------------------------------------------------------------

    \343\ Documented by NERC's April 14, 2005 Long-Term AFC/ATC Task
Force Final Report.
    \344\ TAPS refers the Commission to its August 7, 2006 comments
in Docket No. RM05-25-000 at 21-24.
---------------------------------------------------------------------------

ii. Commission Determination
    1077. The Commission adopts the NOPR proposal not to approve or
remand MOD-004-0 until the ERO submits additional information. Because
the regional procedures have not been submitted to the Commission, it
is not possible to determine at this time whether MOD-004-0 satisfies
the statutory requirement that a proposed Reliability Standard be
``just, reasonable, not unduly discriminatory or preferential, and in
the public interest.'' Accordingly, the Commission neither accepts nor
remands this Reliability Standard until the regional procedures are
submitted. In the interim, compliance with MOD-004-0 should continue on
a voluntary basis, and the Commission considers compliance with the
Reliability Standard to be a matter of good utility practice.
Consistent with Order No. 890 and comments received in response to the
NOPR, the Commission directs the ERO, through the Reliability Standards
development process, to modify MOD-004-0 as discussed below.
    1078. We agree with FirstEnergy that CBM is important for system
reliability by allowing the LSEs to meet their historical, state, RTO
or regional generation reliability criteria requirement such as reserve
margin, loss of load probability, loss of largest units, etc. We agree
with EEI and MidAmerican that transparency of the studies supporting
CBM determination will reduce the opportunity for transmission service
providers to overestimate the amount of CBM and misuse transfer
capability. We therefore direct the ERO to develop Requirements

regarding transparency of the generation planning studies used to
determine CBM values. We also clarify that CBM should only be set aside
upon request of any LSE within a balancing area to meet its verifiable
historical, state, RTO or regional generation reliability criteria
requirement such as reserve margin, loss of load probability, loss of
largest units, etc. We expect verification of the CBM values to be part
of the Requirements with appropriate Measures and Levels of Non-
Compliance.
    1079. We continue to believe this Reliability Standard should be
modified to include a provision ensuring that CBM, TRM and ETC cannot
be used for the same purpose, such as loss of the identical generating
unit. In order to limit misuse of transfer capability set aside as CBM,
we direct the ERO to provide more specific requirements for how CBM
should be determined and allocated across transmission paths or
flowgates. As we stated in Order No. 890, we do not mandate a
particular methodology for allocating CBM to paths or flowgates. For
example, one approach could be based on the location of the outside
resources or spot market hubs that a LSE has historically relied on
during emergencies resulting from an energy deficiency, but we agree
with EEI that flexible rules should be allowed to prevent unnecessary
increase of the generation reserve requirement within the transmission
provider's system. Therefore, we support flexibility, but expect that
the ERO, using its Reliability Standards development process, will
adequately approach these complex technical issues and propose a new
version of MOD-004-0 that addresses the methods for CBM determination
and allocation on paths that will reduce reliability and discrimination
concerns.
    1080. In response to TAPS's question asking how CBM can be viewed
as a Reliability Standard if it is optional to the transmission
provider, our understanding is that transmission providers that have
opted not to use CBM have instead set aside transmission margin (needed
to bring in outside power to meet generation reliability criteria)
either through ETC or TRM. CBM is not the only way to reserve
transmission capacity for a margin. However, if the Reliability
Standard is not clear regarding the method of calculating transmission
margins, it may cause double-counting of transmission margins and
reduction of ATC. As we stated in Order No. 890, we find that clear
specification of the permitted purposes for which entities may reserve
CBM and TRM will virtually eliminate double-counting of TRM and CBM.
Therefore, we direct the ERO to modify its standard in order to prevent
setting aside transfer capability for the same purposes.
    1081. We share TAPS's concern that there is a significant potential
for abuse as a result of the current flexibility afforded to
transmission providers in the calculation of both CBM and TRM. In
response to TAPS's concern, we clarify that in accordance with the OATT
Reform Final Rule and the ERO CBM definition, each LSE has the right to
request CBM be set aside and use it to meet its verifiable historical,
state, RTO or regional generation reliability criteria requirement such
as reserve margin, loss of load probability, loss of largest units,
etc. As such, the LSEs that request CBM be set aside must be identified
as applicable entities with identified Requirements, including
Requirements on generation studies to verify the set aside, Measures
and Levels of Non-Compliance. We direct the ERO to modify the
Reliability Standard accordingly.
    1082. We agree with TAPS that there is a need for clearer
requirements in the standard regarding to whom and how to submit a
request for CBM set-aside, and what the transmission service provider
should do if the sum of all CBM requirements exceeds the amount of
available transfer capability. We direct the ERO to address the
reliability aspects in the Reliability Standards development process
and explore with NAESB whether business practices would be required.
    1083. Accordingly, the Commission neither accepts nor remands MOD-
004-0 until the ERO submits additional information. In the interim,
compliance with MOD-004-0 should continue on a voluntary basis, and the
Commission considers compliance with the Reliability Standard to be a
matter of good utility practice. Although the Commission did not
propose any action with regard to MOD-004-0, it addressed above a
number of concerns regarding the Reliability Standard, consistent with
those set forth in Order No. 890. Therefore, we direct the ERO to
develop modifications to the Reliability Standard through the
Reliability Standards development process to: (1) Clarify that CBM
shall be set aside upon request of any LSE within a balancing area to
meet its verifiable historical, state, RTO or regional generation
reliability criteria; (2) develop requirements regarding transparency
of the generation planning studies used to determine CBM value; (3)
modify the current Requirements to make clear the process for how CBM
is allocated across transmission paths or flowgates; (3) modify its
standard in order to prevent setting aside CBM and TRM for the same
purposes; (4) modify the standard by adding LSE as an applicable entity
and (5) coordinate with NAESB business practice standards.
    1084. We direct the ERO to consider APPA's suggestion that MOD-004-
0 may be redundant and should be eliminated if the ERO develops a
modification to the MOD-002-0 Reliability Standard that includes
reporting requirements
g. Procedure for Verifying Capacity Benefit Margin Values (MOD-005-1)
    1085. MOD-005-1 specifies the requirements regarding the periodic
review of a transmission service provider's adherence to the regional
reliability organization's CBM methodology. It requires each regional
reliability organization to: (1) Develop and implement a procedure to
review at least annually the CBM calculations and the resulting values
determined by member transmission service providers; (2) document its
CBM review procedure and (3) make the results of the most current CBM
review available to NERC upon request.
    1086. In the NOPR, the Commission identified MOD-005-0 as a fill-
in-the-blank standard that requires each regional reliability
organization to develop and implement a procedure to review CBM
calculations and the resulting values and to make the documentation of
the results of the CBM review available to NERC and others. The NOPR
stated that because the regional procedures had not been submitted, the
Commission would not propose to approve or remand MOD-005-0 until the
ERO submits the additional information.
i. Comments
    1087. APPA agrees that MOD-005-0 is a fill-in-the blank standard,
and that in its current form, it is not sufficient and should not be
accepted for approval as a mandatory Reliability Standard until the
necessary regional procedures have been submitted and approved. APPA
suggests that NERC modify MOD-006-0, so that MOD-004-0 and MOD-005-0
could be eliminated.
ii. Commission Determination
    1088. The Commission adopts the NOPR proposal not to approve or
remand MOD-005-0 until the ERO submits additional information. Because
the regional procedures have not been submitted to the Commission, it
is not possible to determine at this time whether MOD-005-0 satisfies
the statutory requirement that a proposed Reliability Standard be
``just,

reasonable, not unduly discriminatory or preferential, and in the
public interest.'' Accordingly, the Commission neither accepts nor
remands this Reliability Standard until the regional procedures are
submitted. In the interim, compliance with MOD-005-0 should continue on
a voluntary basis, and the Commission considers compliance with the
Reliability Standard to be a matter of good utility practice.
    1089. As to APPA's comment on incorporating MOD-004 and MOD-005
into MOD-006, we direct the ERO to consider those comments through the
Reliability Standards development process.
h. Procedure for Use of Capacity Benefit Margin Values (MOD-006-0)
    1090. The purpose of MOD-006-0 is to promote the consistent and
uniform use of transmission CBM calculations among transmission system
users. MOD-006-0 requires that each transmission service provider
document its procedure for the scheduling of energy against a CBM
reservation and make the procedure available on a Web site accessible
by the regional reliability organization, NERC and transmission users.
    1091. In the NOPR, the Commission proposed to approve Reliability
Standard MOD-006-0 as mandatory and enforceable. In addition, the
Commission proposed to direct NERC to submit a modification to MOD-006-
0 that: (1) Includes a provision that will ensure that CBM and TRM are
not used for the same purpose; (2) modifies Requirement R1.2 so that
concurrent occurrence of generation deficiency and transmission
constraints is not a required condition for CBM usage; (3) modifies
Requirement R1.2 to define ``generation deficiency'' based on a
specific energy emergency alert level and (4) expands the applicability
section to include the entities that actually use CBM, such as LSEs.
    1092. In addition, the Commission proposed that NERC should clarify
the requirements to address when and how CBM can be used to reduce
transmission provider discretion with regard to CBM usage. The
Commission provided guidance expressing its belief that CBM should be
used only when the LSE's local generation capacity is insufficient to
meet balancing Reliability Standards, and that CBM should have a zero
value in the calculation of non-firm ATC.
i. Comments
    1093. APPA supports the Commission's proposal to approve MOD-006-0.
Moreover, APPA agrees with the Commission's proposed directives \345\
that the standard should address the use of CBM and TRM for the same
purpose. However, APPA believes that the specificity of the
Commission's proposed directives to NERC, if implemented, would
undermine NERC's role as the approved ERO with the technical expertise
to develop and revise standards for the Commission's subsequent review.
APPA therefore suggests that the Commission in its Final Rule make
clear to NERC its concerns about MOD-006-0, but then let NERC address
those concerns through its Reliability Standard development process.
---------------------------------------------------------------------------

    \345\ NOPR at P 642.
---------------------------------------------------------------------------

    1094. Regarding the Commission's proposal that MOD-006-0 R1.2 be
modified ``so that concurrent occurrence of transmission constraints
and a generation deficiency is not a requirement for CBM usage,'' WEPCO
asserts that the Commission is misinterpreting CBM. WEPCO states that
if there is no transmission constraint then there is no need to use
CBM. In that case, transmission capacity exists for a LSE to import
energy. If there is a transmission constraint, CBM reserves
transmission capacity that the LSE can use to import energy for
reliability needs.
    1095. EEI points out that the explicit intention for CBM is that it
be used only during conditions where there are emergency generation
deficiencies. However, EEI emphasizes that the Commission's
recommendation does not consider that the LSE's supply and demand
balance varies season to season, over time, and with supply and demand
uncertainties. EEI says that the development of CBM quantities must be
carried out in a manner that sets aside transmission capability for
forecasted conditions and uncertainties much like the native load
reservations necessary for serving reasonably-forecasted native load.
An argument may be made that during a period of time when a LSE's
expected reserves are substantially greater than its targeted reserves,
the need for CBM set-aside decreases. However, should the LSE foresee
that this ``excess'' would occur substantially in the future, a
reduction in CBM would not be warranted since substantial uncertainties
still exist.
    1096. Additionally, regarding the Commission's proposal that a LSE
that ``has sufficient generation resources within its balancing
authority to meet the balancing Reliability Standards, should not need
to preserve capacity for CBM at all,'' WEPCO argues that just because
the balancing authority has sufficient generation does not mean that
there is sufficient transmission capacity to deliver the energy to the
LSE. WEPCO states that the LSE may be remote from the bulk of the
balancing authority, so there may be occasions when a LSE that has
sufficient generation resources within its balancing authority to meet
the balancing Reliability Standards may still need to reserve capacity
for CBM. In addition, EEI argues that the Commission's viewpoint does
not take into account the availability of these resources unless they
are under contract with the LSE to provide this service. EEI contends
that the implication of this suggestion is to unduly restrict the
sources of generation capacity available for CBM during times of
generation shortage, which results in the LSE's being captive to local
generation that is available and does not allow access to the market
outside of the LSE's balancing authority. Additionally, EEI cautions
that this action may require the LSE to develop contractual agreements
with local generation and thus increase costs to the LSE's rate payers.
    1097. Given the strong direction on CBM issues in the OATT Reform
NOPR, TAPS assumes that the Commission would not be approving the
Version 0 standards on these competitively crucial issues, but would
continue to address them forcefully in the OATT Reform proceeding. TAPS
notes that, although that is the course largely adopted by the NOPR in
this proceeding, the NOPR \346\ proposes to approve MOD-006-0 and MOD-
007-0, with directions to improve these standards. TAPS notes that such
action is inconsistent with the Commission's general approach to ATC/
TTC/TRM/CBM standards in this docket and the OATT Reform NOPR. TAPS
further states that, given the absence of clear access of non-
transmission owner LSEs to CBM, the proposed expansion of MOD-007-0 to
include such LSEs in the NOPR \347\ seems bizarre.
---------------------------------------------------------------------------

    \346\ Id. at P 642, 648.
    \347\ Id. at P 647-48.
---------------------------------------------------------------------------

ii. Commission Determination
    1098. The Commission adopts the NOPR proposal to approve MOD-006-0
as mandatory and enforceable. Consistent with Order No. 890 and
comments received in response to the NOPR, the Commission directs the
ERO to modify MOD-006-0 as discussed below.
    1099. Consistent with the views of many commenters, we adopt the
NOPR proposal that requires a provision that will ensure that CBM and
TRM are not used for the same purpose. As discussed under MOD-004-0
concerning the

reservation of transfer capacity, we believe that if the Reliability
Standard is not clear regarding the conditions specifying both the
reservation and the use of CBM, it may cause double-counting. Such
double-counting will lead to an unnecessary reduction of ATC, and
create opportunities for discrimination. Therefore, we direct the ERO
to modify its standard to prevent use of CBM and TRM for the same
purposes. We agree with APPA that the ERO should use its Reliability
Standards development process to address the double-counting problem.
    1100. We adopt the NOPR's proposal and direct the ERO to modify
Requirement R1.2 so that a transmission constraint is not a required
condition for CBM usage. The glossary definition and the use as defined
in Order No. 890 is that CBM ``is intended to be used by the LSE only
in time of emergency generation deficiencies.'' \348\ Therefore we
direct the ERO to modify the standard in the manner proposed in the
NOPR.
---------------------------------------------------------------------------

    \348\ See NERC Glossary at 2.
---------------------------------------------------------------------------

    1101. We adopt the NOPR proposal that requires modification of
Requirement R1.2 to define ``generation deficiency'' based on a
specific energy emergency alert level. This approach will provide
clarity as to when the use of CBM may be permitted. We therefore direct
the ERO to modify the Reliability Standard to include a specific energy
emergency alert level that will trigger CBM usage.
    1102. We also reiterate the direction in Order No. 890 that CBM
should have a zero value in the calculation of non-firm ATC because
non-firm service may be curtailed so that CBM can be used. CBM is
reserved as part of the firm transfer capability so that it is
available when needed for energy emergencies. We determine that each
LSE should be permitted to call for use of CBM, provided all of the
other Requirements of R1.1 are met. We direct that CBM may be
implemented up to the reserved value when a LSE is facing firm load
curtailments.
    1103. We adopt the NOPR proposal that CBM should be used only when
the LSE's local generation capacity is insufficient to meet balancing
Reliability Standards, with the clarification that the local generation
is that generation capacity that is either owned or contracted for by
the LSE. We disagree with WEPCO that just because the balancing
authority has sufficient generation does not mean that there is
transmission capacity to deliver the energy to the LSE. The Commission
finds that such a scenario would violate existing transmission
operating and transmission planning Reliability Standards. There is an
explicit requirement in the transmission operating standards that
generation reserves must be deliverable to load.\349\ Also, there is an
explicit requirement in the transmission planning standards that all
firm load must be supplied under various system conditions with and
without contingencies.\350\ The Commission is not prescribing how these
requirements should be met. There are a variety of approaches to do so,
including adequate transmission capability, local or dynamic generation
transfers into the area or DSM. To clarify for EEI, our proposal does
not take into account the availability of these resources unless they
are under contract with the LSE to provide this service. We developed
our NOPR proposal on the rationale derived from the CBM concept, and
believe that if there are enough resources to meet generation
reliability criteria within the balancing authority, there is no need
to request CBM.
---------------------------------------------------------------------------

    \349\ TOP-002-2.
    \350\ TPL-002-0.
---------------------------------------------------------------------------

    1104. We also adopt the NOPR proposal to require the applicability
section to include the entities that actually use CBM, such as LSEs.
The current CBM definition in the NERC glossary determines that LSEs
are users of CBM. Load-serving entities determine when to use CBM,
initiate CBM use and call for its end. Load-serving entities therefore
have to comply with the standard requirements that specify the
conditions under which CBM will be used. We direct the ERO to modify
the standard accordingly.
    1105. With regard to TAPS's comments concerning its assumption that
the Commission would not be approving the Version 0 standards on these
issues, but would continue to address them in the OATT Reform
proceeding, the Commission finds that MOD-006-0 and MOD-007-0 do not
establish CBM values, but rather address CBM implementation and
documentation. The implementation of CBM has critical implications for
the reliable operation of the Bulk-Power System and we find that these
Reliability Standards should be mandatory and enforceable. The
competitively significant issue is to assure that there is no double-
counting of CBM and to determine the magnitude of CBM which is
addressed in other Reliability Standards that the Commission has not
approved or remanded.
    1106. The Commission approves MOD-006-0 as mandatory and
enforceable. In addition, the Commission directs the ERO to develop a
modification to Reliability Standard MOD-006-0 through the Reliability
Standards development process that: (1) Includes a provision that will
ensure that CBM and TRM are not used for the same purpose; (2) provides
that CBM should be used for emergency generation deficiencies; (3)
modifies Requirement R1.2 to define ``generation deficiency'' based on
a specific energy emergency alert level; (4) includes a provision that
CBM should have a zero value in the calculation of non-firm ATC and (5)
expands the applicability section to include the entities that actually
use CBM, such as LSEs.
i. Documentation of the Use of Capacity Benefit Margin (MOD-007-0)
    1107. MOD-007-0 requires transmission service providers that use
CBM to report and post its use.
    1108. In the NOPR, the Commission proposed to approve Reliability
Standard MOD-007-0 as mandatory and enforceable. In addition, the
Commission proposed to direct NERC to submit a modification to MOD-007-
0 that expands the applicability section to include the entities that
actually use CBM, such as LSEs.
i. Comments
    1109. APPA supports the Commission's proposed approval of MOD-007-
0. However, it believes that the issue of whether LSEs should be made
subject to MOD-007-0 should be left to NERC in the first instance to
decide. In so doing, NERC should consider expanding MOD-007-0 to cover
not only LSEs, but also balancing authorities. Under NERC's Functional
Model, the balancing authority is the entity that would schedule energy
over transmission capacity reserved as CBM. Moreover, it is the
balancing authority that would know the information necessary to report
an incident during which the balancing authority had to import energy
from outside the balancing authority's own area from a resource
designated as operating reserves and change the net scheduled
interchange with the neighboring balancing authorities to allow the
energy to flow into the balancing authority's area.
ii. Commission Determination
    1110. The Commission approves MOD-007-0 as mandatory and
enforceable. Consistent with the comments received in response to the
NOPR, the Commission directs the ERO

to modify the standard as discussed below.
    1111. We also adopt the NOPR's proposal to require the
applicability section to include the entities that actually use CBM and
report on their CBM use, such as LSEs. The current CBM definition in
the NERC glossary determines when a LSE is a CBM user. The LSE
determines how much CBM will be set aside, when CBM use will start and
when it will end. The LSE must therefore comply with the standard
requirements that require reporting and posting of CBM use. We direct
the ERO to modify the standard to include the entities that actually
use CBM, such as LSEs. In addition, we agree with APPA that the
Reliability Standard should apply to balancing authorities and direct
the ERO to include balancing authorities within the entities to which
this standard is applicable.
    1112. Accordingly, the Commission approves MOD-007-0 as mandatory
and enforceable. In addition, the Commission directs the ERO to develop
a modification through its Reliability Standards development process
that expands the applicability of MOD-007-0 to include the entities
that actually use CBM, such as LSEs and balancing authorities.
j. Documentation and Content of Each Regional Transmission Reliability
Margin Methodology (MOD-008-0)
    1113. MOD-008-0 requires the development and posting of a regional
methodology for TRM, which is transmission capacity that is reserved to
provide reasonable assurance that the interconnected transmission
network will remain secure under various system conditions. The
Reliability Standard requires each regional reliability organization
to: (1) Develop and document a regional TRM methodology in conjunction
with its members and (2) post on a Web site the most recent version of
its TRM methodology.
    1114. In the NOPR, the Commission identified MOD-008-0 as a fill-
in-the-blank standard, proposing that because the regional
methodologies had not been submitted, the Commission would not propose
to approve or remand MOD-008-0 until the ERO submitted the additional
information. The Commission expressed concern about the lack of: (1)
Clear requirements on how TRM should be calculated and allocated across
paths and (2) consistent criteria and clarity with regard to the entity
on whose behalf TRM had been set aside.
    1115. The Commission requested comment in the NOPR on how TRM is
currently calculated and allocated across paths, and what would be a
recommended approach for the future.
i. Comments
    1116. APPA agrees that MOD-008-0 is a fill-in-the-blank standard,
is not sufficient as currently drafted, and should not be approved as a
mandatory Reliability Standard until NERC and the regional reliability
organizations and regional entities develop the necessary regional
methodologies and the Commission approves them.
    1117. MISO adds that there should be a consistent framework to be
followed by entities in determining TRM. It states that relevant MOD
standards should be revised if such a framework is not clearly
delineated. However, MISO cautions that a Reliability Standard should
not be used to address a perceived equity concern. MidAmerican also
supports greater uniformity of TRM definitions and calculations, and
proposes that a revised standard and/or new standards should encourage
transparency with increased availability of information, consistent
data input and certain modeling assumptions. International Transmission
agrees and proposes that TRM consistency should be addressed either on
a regional basis or on an Interconnection-wide basis.
    1118. In response to the Commission's request for comments on the
current calculation of TRM, and recommended approaches for the future,
International Transmission provides a description of the MISO approach
to TRM. International Transmission states that during the operating
horizon (next 48 hours), TRM is limited to a reserve sharing component
which only applies to flowgates that are not based on transmission
outages (unit tripping and transmission outages are considered a double
contingency). International Transmission states that the logic behind
this approach is that there are fewer uncertainties in the operating
horizon because schedules and market flows are known. International
Transmission explains that during the planning horizon (next 48 hours),
a two percent TRM component for uncertainty is used on all flowgates,
including those requiring reserve sharing TRM. In addition, other
assumptions regarding the sale of transmission service enter into the
need for TRM to cover ``uncertainties.'' In addition, International
Transmission cautions that MISO's minimal two percent margin may not be
sufficient for long-term planning horizon requests (i.e., over 13
months) if planning ``assumptions'' are not reasonable. International
Transmission argues that MISO must also employ proper sensitivity
studies to other system variables for a two percent margin to be
sufficient. TRMs in the five to ten percent range are not necessarily
unreasonable if a wide range of potential system operating conditions
is not studied. Regardless of the ultimate approach adopted in future
standards, International Transmission proposes that all entities follow
a consistent framework when calculating TRM.
    1119. MidAmerican responds with a discussion of its current
approach to TRM calculation, which has been performed in accordance
with MAPP-approved methodologies. MidAmerican states that these
methodologies include an amount to allow for both the delivery of
operating reserves and for uncertainties. Since delivery of operating
reserves keeps the interconnected network in service, benefiting all
market participants, MidAmerican contends that it is appropriate for
TRM to include an amount to allow for the delivery of operating
reserves. The allowance for uncertainty is calculated as a percentage
of TTC required to protect reliability. All market participants benefit
from the provision of an appropriate margin for uncertainty because the
reliability of the interconnected network is maintained and service
interruptions are reasonably minimized.
    1120. With respect to applicable entities, APPA proposes the
addition of two new functional entities. Specifically, APPA believes
that NERC should expand the applicability section of MOD-008-0 to
include planning authorities and reliability coordinators. APPA points
out that these are the only entities that can evaluate the amount of
error in their transfer capability predictions.
    1121. ERCOT states that the Commission's concerns about TRM do not
apply to ERCOT, because ERCOT has a balanced grid in which all
transmission is firm, no transmission is reserved and there are no
transmission paths.
ii. Commission Determination
    1122. The Commission does not approve or remand MOD-008-0 until the
ERO submits additional information. Consistent with Order No. 890 and
comments received in response to the NOPR, the Commission directs the
ERO to modify MOD-008-0 through the Reliability Standards development
process, as discussed below.
    1123. Consistent with the NOPR proposal and Order No. 890, the
Commission directs the ERO to modify standard MOD-008-0 to clarify how
TRM should be calculated and allocated

across paths or flowgates. We understand that the standards drafting
process is underway as a joint project with NAESB. We agree with
International Transmission, MidAmerican and MISO about the need for
more uniformity and transparency in TRM calculation methodology and
use, in order to eliminate potential reliability and discrimination
concerns. Consistent with Order No. 890, the Commission directs the ERO
to specify the parameters for entities to use in determining
uncertainties for which TRM can be set aside and used, such as: (1)
Load forecast and load distribution error; (2) variations in facility
loadings; (3) uncertainty in transmission system topology; (4) loop
flow impact; (5) variations in generation dispatch; (6) automatic
reserve sharing and (7) other uncertainties as identified through the
NERC Reliability Standards development process. We find that clear
specification in this Final Rule of the permitted purposes for which
entities may reserve CBM and TRM will also virtually eliminate double-
counting of TRM and CBM. Therefore, we direct the ERO to determine
clear requirements regarding permitted uses for TRM through its
Reliability Standards development process.
    1124. We agree with the commenters that the percentage reduction of
line rating can be one way to establish an appropriate maximum TRM if
thermal considerations are the only limiting factors. While this is a
relatively simple method, it ignores limitations relative to voltage or
stability limitations which are the more typical reasons for
transmission limitations. If adopted as the Reliability Standard
method, it should not restrict a transmission provider from using a
more sophisticated method that may allow for greater ATC without
reducing overall reliability. However, we disagree with the use of an
arbitrary percentage over a long time frame that is not based on either
proven historical need or sensitivity studies that support that
determination. Therefore, consistent with our OATT Reform Final Rule,
we direct the ERO to develop requirements regarding transparency of the
documentation that supports TRM determination.
    1125. We agree with APPA that NERC should revise the applicability
section of this standard to add planning authorities and reliability
coordinators, and in addition, any other entities that may be
identified in the Reliability Standards development process.
    1126. Regarding ERCOT's statement that TRM does not apply to ERCOT,
we reiterate our position that any request for a regional exemption
from the applicable Reliability Standards must take place in the
Reliability Standards development process.
    1127. The Commission neither accepts nor remands MOD-008-0 until
the ERO submits additional information. In the interim, compliance with
MOD-008-0 should continue on a voluntary basis, and the Commission
considers compliance with the Reliability Standard to be a matter of
good utility practice. Although the Commission did not propose any
action with regard to MOD-008-0, it addressed above a number of
concerns regarding the Reliability Standard, consistent with those
proposed in Order No. 890. Accordingly, we direct the ERO to develop
modifications to the Reliability Standard through the Reliability
Standards development process including: (1) Clear requirements on how
TRM should be calculated, including a methodology for determining the
maximum TRM value, and allocated across paths; (2) clear requirements
for permitted purposes for which TRM can be set aside and used; (3)
clear requirements for availability of documentation that supports TRM
determination and (4) expanding the applicability to add planning
authorities and reliability coordinators and any other appropriate
entity identified in the Reliability Standards development process.
k. Procedure for Verifying Transmission Reliability Margin Values (MOD-
009-0)
    1128. MOD-009-0 requires each regional reliability organization to
develop and implement a procedure to review TRM calculations and the
resulting values determined by member transmission providers to ensure
compliance with the regional TRM methodology.
    1129. In the NOPR, the Commission identified MOD-009-0 as a fill-
in-the-blank standard that requires each regional reliability
organization to develop a procedure for review of TRM calculations and
the resulting values. In the NOPR, the Commission stated that because
the regional procedures had not been submitted, the Commission would
not propose to approve or remand MOD-009-0 until the ERO submits the
additional information.
i. Comments
    1130. APPA agrees that MOD-009-0 is a fill-in-the-blank standard,
is not sufficient as currently drafted, and should not be approved as a
mandatory Reliability Standard until NERC and the regional reliability
organizations and regional entities develop the necessary regional
methodologies and the Commission approves them.
ii. Commission Determination
    1131. The Commission will not approve or remand MOD-009-0 until the
ERO submits additional information. Because the regional procedures
have not been submitted to the Commission, it is not possible to
determine at this time whether MOD-009-0 satisfies the statutory
requirement that a proposed Reliability Standard be ``just, reasonable,
not unduly discriminatory or preferential, and in the public
interest.'' Accordingly, the Commission neither approves nor remands
this Reliability Standard until the regional procedures are submitted.
In the interim, compliance with MOD-009-0 should continue on a
voluntary basis, and the Commission considers compliance with the
Reliability Standard to be a matter of good utility practice.
l. Steady-State Data for Modeling and Simulation of Interconnected
Transmission System (MOD-010-0)
    1132. The purpose of this Reliability Standard is to establish
consistent data requirements, reporting procedures and system models
for use in reliability analysis. MOD-010-0 requires the transmission
owner, transmission planner, generator owner and resource planner to
provide steady-state data, such as equipment characteristics, system
data, and existing and future interchange schedules to the regional
reliability organization, NERC, and other specified entities.
    1133. In the NOPR, the Commission proposed to approve Reliability
Standard MOD-010-0 as mandatory and enforceable. In addition, the
Commission proposed to direct NERC to submit a modification to MOD-010-
0 that: (1) Adds a new requirement for transmission owners to provide
the list of contingencies they use in performing system operation and
planning studies and (2) expands the applicability section to include
the planning authority.
i. Comments
    1134. APPA agrees with the Commission that MOD-010-0 is sufficient
for approval as a mandatory and enforceable Reliability Standard. APPA
believes, however, that the Commission's proposed directives to NERC to
revise this standard are unduly prescriptive, and may not in fact be
the best way to revise the standard.
    1135. ISO/RTO Council and ISO-NE do not support adoption of this
standard because its requirements refer several

times to the data requirements and reporting procedures specified in
MOD-011-0, which has been identified by the Commission as a fill-in
the-blank standard. ISO/RTO Council and ISO-NE argue that demonstrating
compliance with MOD-010-0 is dependent on an unapproved standard, that
the unapproved standard lacks some required criteria or procedures that
must be developed by the regional reliability organization, that MOD-
010-0 cannot be effectively implemented, and that responsible entities
therefore should not be subject to compliance with an incomplete
standard.
    1136. Constellation strongly supports the Commission's proposals
with respect to MOD-010-O and MOD-012-0 because these proposals,
together with other initiatives, such as OATT reform, represent
additional steps not only to achieving a reliable bulk power system,
but also to reducing undue discrimination in transmission services.
Constellation supports the Commission's proposals because they will
involve generation owners in facility ratings discussions and
discussions of other limiting components and will provide more clarity
in the requirements of the Reliability Standard, making enforcement
more objective and robust.
    1137. Many commenters submitted comments both supporting and
opposing the Commission's proposal to modify the standard to require
listing the contingencies that transmission owners use when they
perform system operation and planning studies.
    1138. FirstEnergy supports the Commission's proposal to require
transmission owners to provide the list of contingencies used in
performing system operation and planning studies. FirstEnergy
emphasizes that such a requirement, however, should accommodate various
electronic formats that are commonly used in industry simulation tools.
FirstEnergy states that compliance with this Reliability Standard
should not require transmission owners to replace existing computer
and/or software systems, and that the new standard should also require
the regional reliability organizations (or Regional Entities) to
coordinate the lists of contingencies across wide-areas.
    1139. In its support of the Commission's proposal, MidAmerican and
TANC stress that a requirement that the transmission owner provide a
list of contingencies to neighboring systems will benefit reliability
by enabling neighboring systems to accurately study the effects of
contingencies on their own systems. In its concurring comments, TANC
recommends that the Commission clarify that the list of the
contingencies that are used in performing system operation and planning
studies include all the contingencies, N-1, N-2, as well as multiple
contingencies.
    1140. MidAmerican cautions that a list of contingencies could be
used in a ``cook-book'' manner to reach the wrong conclusions. A
contingency must be modeled in specific and appropriate conditions to
understand the reliability issues associated with the contingency.\351\
Similarly, NERC states that there may be a need to better understand
the reliability need for transmission owners to provide a list of
contingencies and to whom the list should be provided.
---------------------------------------------------------------------------

    \351\ MidAmerican further cautions that other contingencies
exist that must be studied under still-different conditions.
Advanced applications associated with real-time contingency analysis
review an extensive list of events in combination with other events.
Ahead of time, there is no way to be sure exactly which events are
the worst in any given operating condition. A single reliability
standard cannot contain all the coordination that is needed to allow
a system to fully understand all the reliability challenges of a
neighboring system. Thus, MidAmerican contends that a better
approach is to continue the joint operational and long-term planning
that planning authorities, reliability coordinators and other
regional entities are currently conducting with transmission
planners, transmission owners and others to ensure that the
interconnected network is operated and planned in a coordinated way.
---------------------------------------------------------------------------

    1141. Northern Indiana and MidAmerican note that such a list of
contingencies should be considered a particularly sensitive form of
CEII since it would be a list of events that, when they occur, cause
critical situations on a system. Northern Indiana and MidAmerican argue
that the Commission should include the need to provide for protection
against public disclosure through the NERC administrative process in
its discussion of any final Reliability Standard. In addition,
California Cogeneration states that Requirements R1 and R2 of this
standard should not apply to entities that have no material impact on
the grid. California Cogeneration warns that the standard may also
require generator owners to provide data on behind-the-meter
operations, the provision of which should be seriously limited, and
data on future interchange schedules, the confidentiality of which
should be maintained.
    1142. PG&E and Xcel oppose the proposed modification requiring a
list of contingencies stating that the requirement is unnecessary and
would be unduly burdensome. Xcel also states that the modification
would not prove to be useful to neighboring systems. No such lists are
currently developed or maintained today. Rather, the contingencies are
reflected in the computerized models used by transmission providers for
both transmission planning and operations. The models are regularly
updated as new facilities are installed. If transmission operators are
required to develop such lists, they would be so long and subject to
constant change that they would not only be burdensome to develop and
maintain, but also unlikely to provide useful information for other
transmission owners.
    1143. In its opposition to releasing a list of contingencies, PG&E
states that performing transmission planning studies is an ambiguous
part of the duties of a transmission owner under the NERC Functional
Model. Further clarification and refinement of the responsibilities of
each entity under the NERC Functional Model may indicate that such
studies are among a transmission owner's duties. Until that happens,
however, requiring transmission owners to provide contingencies used in
performing system operation and planning studies is inappropriate.
    1144. SoCal Edison and TVA state that the entity that should be
responsible for providing a list of contingencies in performing
planning and operation studies is the transmission planner, not the
transmission owner. APPA also believes that the transmission operator
should be one of the entities required to list contingencies used to
perform studies, and that the transmission owner function should be
removed as an applicable entity. APPA further notes that the
transmission owner does no studies regarding operations or planning. A
transmission owner merely owns transmission facilities and maintains
those facilities. Moreover, APPA argues that existing studies performed
by the transmission planner for the regional reliability organization
or planning authority will include a list of contingencies.
    1145. Regarding the Commission's proposal to expand the
applicability section of this Reliability Standard to include the
planning authority, APPA disagrees and recites the comments of MRO,
Reliability First and PG&E on the Staff Preliminary Assessment,\352\
that to require the planning authority to provide all of this
information is duplicative and unnecessary. APPA believes that NERC, as
the entity charged with developing standards, is best-suited to address
all of these

concerns and to develop a consensus standard using its Reliability
Standard development process.
---------------------------------------------------------------------------

    \352\ NOPR at P 663.
---------------------------------------------------------------------------

    1146. TAPS states that this standard would impose unnecessary costs
on small systems without improving reliability if applied without the
limitation of NERC's bulk electric system definition and NERC's June
registry criteria. TAPS opines that modeling will be complicated by the
incorporation of low voltage or radial transmission facilities or small
generators that have no material impact on bulk transmission system
reliability, without improving the results. TAPS further argues that
NERC and the Regional Entities--not the Commission--should determine
the level of modeling required for reliability.
ii. Commission Determination
    1147. The Commission approves MOD-010-0. In addition, the
Commission requires the ERO to modify MOD-010-0 as described below.
    1148. As an initial matter, the Commission disagrees that MOD-010-0
cannot be implemented until MOD-011-0 is modified. We have directed
that data collection and reporting procedures not be interrupted while
MOD-011-0 is being modified. Therefore it is possible to implement MOD-
010-0. Failure to have the data needed for the steady-state analysis
would halt regional reliability assessment processes and hinder
planners from accurately predicting future system conditions, which
would be detrimental to system reliability. We therefore direct the ERO
to use its authority pursuant to Sec.  39.2(d) of our regulations to
require users, owners and operators to provide to the Regional Entity
the information related to data gathering, data maintenance,
reliability assessments and other process-type functions. As we discuss
below in the section on MOD-011-0, we direct the ERO to develop a Work
Plan that will facilitate ongoing collection of the steady-state
modeling and simulation data set forth in MOD-011-0, and submit a
compliance filing with that Work Plan.
    1149. Supported by many commenters, we adopt the NOPR proposal to
direct the ERO to modify MOD-010-0 to require filing of all of the
contingencies that are used in performing steady-state system operation
and planning studies. We believe that access to such information will
enable planners to accurately study the effects of contingencies
occurring in neighboring systems on their own systems, which will
benefit reliability. Because of the lack of information on contingency
outages and the automatic actions that result from these contingencies,
planners have not been able to analyze neighboring conditions
accurately, thereby potentially jeopardizing reliability on their own
and surrounding systems. This requirement will make transmission
planning data more transparent, consistent with Order No. 890 requiring
greater openness of the transmission planning process.
    1150. With respect to TANC's recommendation to modify the standard
to require utilities to provide lists of all contingencies they use to
operate and plan their systems (N-1, N-2, multiple), we clarify that
our requirement specifies contingency files used for all operations and
planning. We do not limit the provision of contingency information to
single, double or multiple outages. Utilities must provide lists of all
the contingencies they use in operations and planning, provided in
their original format, regardless of how this data is organized.
    1151. In response to MidAmerican, NERC and TANC's concerns that the
contingency lists could be used as a ``cook-book,'' our expectation is
that utility planners that use these files will have sufficient
experience to use them appropriately. We expect that most utility
planners are already familiar with their neighbors' system topologies,
and have the means, such as bus abbreviation directories and switching
diagrams, to identify facilities listed in contingency files.
    1152. We agree with FirstEnergy's comments regarding the importance
of using existing data collection systems so as to not impose any
additional costs on entities. They may file the contingency files in
the electronic format in which they were created, along with any
necessary decoding instructions. We therefore disagree with PG&E, TAPS
and Xcel that this Reliability Standard will be unduly burdensome since
it only requires the provision of files that must be developed during
the utility's usual planning and operations study process.
    1153. Consistent with California Cogeneration, Northern Indiana and
MidAmerican's concerns, we determine that those data that a company
considers confidential, commercially-sensitive or security-sensitive
should be released in accordance with the CEII process or subject to
confidentiality agreements. We direct the ERO to address
confidentiality issues and modify the Reliability Standard as necessary
through its Reliability Standards development process.
    1154. We disagree with commenters that generators or small entities
that do not have a material impact on grid reliability should be
automatically exempt from providing the data required by this
Reliability Standard. The Commission believes that all entities that
are required to register under the registration process that we have
approved must provide data requested by the ERO or the Regional Entity.
    1155. We agree with APPA, SoCal Edison and TVA that the functional
entity responsible for providing the list of contingencies in
performing planning studies should be the transmission planner, instead
of the transmission owner, as proposed in the NOPR. We also agree with
APPA that the transmission operator should be one of the entities
required to list contingencies used to perform operational studies.
Transmission operators are usually responsible for compiling the
operational contingency lists for both normal and conservative
operation. Therefore, we direct the ERO to modify MOD-010-0 to include
transmission operators as an applicable entity.
    1156. We adopt our NOPR proposal that the planning authority should
be included in this Reliability Standard because the planning authority
is the entity responsible for the coordination and integration of
transmission facilities and resource plans, as well as one of the
entities responsible for the integrity and consistency of the data. We
disagree with APPA that it is duplicative and unnecessary to require
the planning authority to provide all of this information. However, we
direct the ERO, as the entity charged with developing Reliability
Standards, to address all of these concerns and to develop a consensus
standard using its Reliability Standard development process.
    1157. Accordingly, the Commission approves MOD-010-0 as mandatory
and enforceable. In addition, the Commission directs the ERO to develop
a modification to MOD-010-0 through the Reliability Standards
development process that: (1) Adds a new requirement in MOD-010-1 for
transmission planners to provide the contingency lists they use in
performing system operation and planning studies, contained in the
electronic format in which they were created, along with any necessary
decoding instructions and (2) expands the applicability section to
include transmission operators and the planning authority. We also
direct the ERO to address confidentiality and small entity issues
through the Reliability Standards development process.

m. Maintenance and Distribution of Steady-State Data Requirements and
Reporting Procedures (MOD-011-0)
    1158. The purpose of MOD-011-0 is to establish consistent data
requirements, reporting procedures and system models for use in
reliability analysis. This Reliability Standard requires the regional
reliability organizations to develop comprehensive steady-state data
requirements and reporting procedures needed to model and analyze the
steady-state conditions for each Interconnection.
    1159. In the NOPR, the Commission identified MOD-011-0 as a fill-
in-the-blank standard that requires each regional reliability
organization to develop comprehensive steady-state data requirements
and reporting procedures needed to model and analyze the steady-state
conditions for each Interconnection. The NOPR stated that because the
regional methodologies had not been submitted, the Commission would not
propose to approve or remand MOD-011-0 until the ERO submits the
additional information. In addition, the NOPR suggested that the
planning authority plays a significant role in integration of data and
thus should be included in the applicability section of MOD-011-0.
i. Comments
    1160. APPA agrees with the Commission that this standard is a fill-
in-the-blank standard, is not sufficient as currently drafted and
should not be approved as a mandatory reliability standard until NERC
and the Regional Entities develop the necessary methodologies and the
Commission approves them.
    1161. TANC supports replacing the term regional reliability
organization with an entity from the NERC Functional Model.
ii. Commission Determination
    1162. The Commission will not approve or remand MOD-011-0 until the
ERO submits additional information. The Commission directs the ERO to
modify MOD-011-0 as discussed below.
    1163. We reiterate our position stated in the NOPR that the
planning authority should be included in this Reliability Standard
because the planning authority is the entity responsible for the
coordination and integration of transmission facilities and resource
planning, as well as one of the entities responsible for the integrity
and consistency of the data. Therefore, we direct the ERO to add the
planning authority to the applicability section of this Reliability
Standard.
    1164. In response to concerns raised in MOD-010-0 about
implementing MOD-010-0 without the data to be collected when MOD-011-0
is modified, we direct the ERO to develop a Work Plan that will
facilitate ongoing collection of the steady-state modeling and
simulation data specified in MOD-011-0.
    1165. Accordingly, the Commission neither accepts nor remands MOD-
011-0 until the ERO submits additional information. Because the
regional procedures have not been submitted to the Commission, it is
not possible to determine at this time whether MOD-011-0 satisfies the
statutory requirement that a proposed Reliability Standard be ``just,
reasonable, not unduly discriminatory or preferential, and in the
public interest.'' In the interim, compliance with MOD-011-0 should
continue on a voluntary basis, and the Commission considers compliance
with the Reliability Standard to be a matter of good utility practice.
We direct the ERO to modify the Reliability Standard through the
Reliability Standards development process to expand the applicability
section to include the planning authority. Additionally, we direct the
ERO to develop a Work Plan and submit a compliance filing that will
facilitate ongoing collection of the steady-state modeling and
simulation data specified in MOD-011-0.
n. Dynamics Data for Modeling and Simulation of the Interconnected
Transmission System (MOD-012-0)
    1166. The purpose of MOD-012-0 is to establish consistent data
requirements, reporting procedures and system models for use in
reliability analysis. MOD-012-0 requires transmission owners,
transmission planners, generator owners and resource planners to
provide dynamic system modeling and simulation data, such as equipment
characteristics and system data, to the regional reliability
organization, NERC and other specified entities.
    1167. In the NOPR, the Commission proposed to approve Reliability
Standard MOD-012-0 as mandatory and enforceable. In addition, the
Commission proposed to direct NERC to submit a modification to MOD-012-
0 that: (1) Adds a new requirement for transmission owners to provide
the list of faults or disturbances they use in performing dynamics
system modeling analysis for system operation and planning and (2)
expands the applicability section to include the planning authority.
i. Comments
    1168. APPA and PG&E agree that the Commission should approve MOD-
012-0 as a mandatory and enforceable Reliability Standard. However,
PG&E requests the Commission to approve this standard without any
modifications. In addition, APPA states that the Commission's proposed
directives to NERC to revise this standard are unduly prescriptive, and
may not in fact be the best way to revise the standard. APPA notes that
NERC, as the technical expert body charged with developing standards,
is the entity best suited to hear all of these concerns, and to develop
a consensus standard using its Reliability Standards development
process.
    1169. ISO/RTO Council and ISO-NE disagree with the Commission's
proposal to approve this standard, and state that the MOD-012-0
requirements refer several times to the ``data requirements and
reporting procedures of MOD-013-0,'' which has been identified by the
Commission as a fill-in-the-blank standard, and is pending.
Consequently, they argue that MOD-012-0 cannot be effectively
implemented, and responsible entities should therefore not be subject
to compliance with an incomplete standard.
    1170. With respect to the Commission's proposal for adding a new
requirement to this standard, FirstEnergy notes that it is appropriate
for the Commission to require transmission owners to provide the list
of faults or disturbances used in performing dynamics system studies.
However, FirstEnergy cautions that such requirement should accommodate
various electronic formats that are commonly used in industry
simulation tools. FirstEnergy states that compliance with this
provision should not require transmission owners to replace existing
computer and/or software systems, and that the new standard should also
require the regional reliability organizations (or Regional Entities)
to coordinate the lists of faults or disturbances across wide-areas.
    1171. MidAmerican agrees that requiring transmission owners to
provide a list of faults or disturbances to neighboring systems would
provide for additional coordination between neighboring utilities, and
therefore, would be an improvement to the standard.
    However, MidAmerican warns that a list of faults and disturbances
could be

used in a ``cook-book'' manner to reach the wrong conclusions.\353\
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    \353\ MidAmerican further discusses that the Commission should
recognize that caution must be taken in assuming that no other
faults and disturbances exist that must be studied under other
conditions. MidAmerican states that like with MOD-010-0, ahead of
time, there is no way to be sure exactly which faults and
disturbances are the worst under given operating conditions. A
single reliability standard cannot contain all the coordination
needed to allow each system operator to fully understand all the
reliability challenges of a neighboring system. Perhaps a better
approach is to continue the joint operational and long-term planning
that is currently being conducted by planning authorities,
reliability coordinators and other regional entities with
transmission planners, transmission owners and others to ensure that
the interconnected network is operated and planned in a coordinated
way.
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    1172. Northern Indiana and MidAmerican note that such a list of
faults and disturbances should be considered a particularly sensitive
form of CEII since it would be a list of events that, when they occur,
cause critical problems on the system. Northern Indiana and MidAmerican
request the Commission to protect sensitive information through the
NERC administrative process discussed in the TOP-005-1 Reliability
Standard.
    1173. Xcel raises the same concern it stated about MOD-010-0 that
the proposed modification related to a list of faults and disturbances
is unduly burdensome and would not prove useful to neighboring systems.
Xcel states that no such lists are currently developed or maintained
today, but that the faults and disturbances are reflected in the
computerized models used by transmission providers for both
transmission planning and operations, which are regularly updated as
new facilities are installed. Xcel cautions that the lists, as proposed
by the Commission, would be so long and subject to constant change that
they would not only be burdensome to develop and maintain, but also
unlikely to provide usable information for other transmission owners.
    1174. PG&E disagrees with the Commission's proposal related to
lists of faults and disturbances, and repeats its comments from MOD-
010-0 that this new requirement is unnecessary.
    1175. Regarding the functional entities to which this standard
applies, APPA notes that the transmission operator and transmission
planner, as functions required to provide information regarding
stability studies, should be added to the list of applicable entities,
while transmission owners should be removed from such list. Under the
NERC Functional Model, transmission owners do not perform any studies
related to MOD-012-0. Rather, a transmission owner merely owns
transmission facilities and maintains them.
    1176. California Cogeneration states that this standard raises
concerns about data collection and the cost of compliance, and
therefore a mechanism for determining no material impact and a
provision for exemption is essential for this standard. California
Cogeneration also believes that it is unclear what data is included in
``dynamics system modeling and simulation data,'' and whether
independent generators would have such data.
ii. Commission Determination
    1177. The Commission approves MOD-012-0 as mandatory and
enforceable. The Commission directs the ERO to modify MOD-012-0 as
discussed below.
    1178. As an initial matter, the Commission disagrees that MOD-012-0
cannot be implemented until MOD-013-1 is modified. We have directed
that data collection and reporting procedures not be interrupted while
MOD-013-1 is being revised, therefore it is possible to implement MOD-
012-0. Failure to provide the data needed for dynamics system modeling
and simulation would halt regional reliability assessment processes and
impede planners from accurately predicting future system conditions,
which would be detrimental to system reliability. We therefore direct
the ERO to use its authority pursuant to Sec.  39.2(d) of our
regulations to require users, owners and operators to provide to the
Regional Entities the information related to data gathering, data
maintenance, reliability assessments and other process type functions.
As we will discuss in the next section on MOD-013-1, we require the ERO
to develop a Work Plan and submit a compliance filing that will
facilitate ongoing collection of the dynamics system modeling and
simulation data specified by the deferred MOD-013-1 Reliability
Standard, which is necessary for implementation of MOD-012-0.
    1179. Supported by several commenters, we adopt the NOPR proposal
and direct the ERO to modify MOD-012-0 by adding a new requirement to
provide a list of the faults and disturbances used in performing
dynamics system studies for system operation and planning. We believe
that access to such information will enable planners to accurately
study the effects of disturbances occurring in neighboring systems on
their own systems, which will benefit reliability. This requirement
will also make transmission planning data more transparent, consistent
with Order No. 890, which calls for greater openness of the
transmission planning process on a regional basis.
    1180. In response to MidAmerican's concern that fault and
disturbance information could be used as a ``cook-book,'' our
expectation is that utility planners who use this data have sufficient
experience to use it and interpret the results correctly. We expect
that most utility planners are already familiar with their neighbors'
system topologies, and will be capable of identifying facilities on
fault and disturbance lists.
    1181. We agree with FirstEnergy's concerns regarding the importance
of using existing data collection systems so as to not impose any
additional costs on entities. They may file the fault and disturbance
information in the electronic format in which they were created, along
with any necessary decoding instructions. Compliance with this
provision should not require transmission planners to replace existing
computer and/or software systems. Therefore, we disagree with PG&E and
Xcel that this standard modification will be unduly burdensome.
    1182. Consistent with California Cogeneration, Northern Indiana and
MidAmerican's concerns, we determine that the data that a company
considers confidential, market-sensitive or security-sensitive should
be released in accordance with the CEII process or subject to
confidentiality agreements. We direct the ERO to address
confidentiality issues and modify the standard as necessary through its
Reliability Standards development process.
    1183. We disagree with commenters that generators or small entities
that do not have a material impact on grid reliability should be
automatically exempt from providing the data required by this
Reliability Standard. The Commission believes that all entities that
are required to register under the registration process that we have
approved must provide data requested by the ERO or the Regional Entity.
    1184. We agree with APPA that the functional entity responsible for
providing the fault and disturbance list should be the transmission
planner, instead of the transmission owner, as proposed in the NOPR. We
also agree with APPA that the transmission operator should be added to
the list of applicable entities in the Reliability Standards
development process. Therefore, we direct the ERO to modify

MOD-012-0 to require the transmission planner to provide fault and
disturbance lists.
    1185. We adopt our NOPR proposal that planning authorities should
be included in this Reliability Standard because the planning authority
is the entity responsible for the coordination and integration of
transmission facilities and resource plans, as well as one of the
entities responsible for the integrity and consistency of the data. We
therefore direct the ERO to add the planning authority to the list of
applicable entities.
    1186. Accordingly, the Commission approves MOD-012-0 as mandatory
and enforceable. In addition, the Commission directs the ERO to develop
a modification to MOD-012-0 through the Reliability Standards
development process that: (1) Adds a new requirement for transmission
planners to provide the list of faults and disturbances they use in
performing dynamic stability analysis in the electronic format in which
they were created, along with any necessary decoding instructions and
(2) expands the applicability section to include transmission
operators, planning authorities and transmission planners. We expect
the ERO to address confidentiality issues and modify the Reliability
Standard as necessary through the Reliability Standards development
process.