include in their OATTs by reference.\154\ Occidental claims that this
process would ensure industry input in the development of the
methodology for ATC calculations, as well as Commission review and
approval of the methodology.
---------------------------------------------------------------------------

    \153\ Citing Standards for Business Practices and Communication
Protocols for Pub. Utils., Order No. 676, 71 FR 26199 (May 4, 2006),
FERC Stats. & Regs. ] 31,216 (2006), order on reh'g, Order No. 676-
A, 116 FERC ] 61,255 (2006).
    \154\ Citing id. at P 20.
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    217. Several commenters raise concerns that six months may not be
sufficient time to develop ATC-related reliability standards and
business practices.\155\ Exelon, MidAmerican and NARUC propose that the
Commission grant NERC one year from the date of the Final Rule to
develop the necessary reliability standards. NARUC agrees with one
year, but requests flexibility to assure that the NERC and NAESB
processes can be adequately completed. NERC also states that it expects
the standards development process, already underway, to be finalized
with standards submitted to the Commission prior to the summer of 2007.
LPPC recommends that, within six months of the issuance of the Final
Rule, NERC be required to submit a progress report addressing the
status and a work plan for conclusion within the ensuing six months.
NRECA proposes that the Commission closely monitor the NERC and NAESB
process. Some commenters strongly oppose a flexible deadline, and urge
the Commission to establish a firm deadline that must be met.\156\
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    \155\ E.g., Constellation, Duke, EEI, Exelon, LPPC, MidAmerican,
NARUC, Northwest IOUs, Public Power Council, CREPC, Southern, TDU
Systems, and WestConnect.
    \156\ E.g., Utah Municipals and Entegra.
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    218. At the October 12 Technical Conference, NERC informed
participants that a great deal of progress has been made since the
proposed standards developed by the NERC Standard Committee in February
2006 were generated to address the recommendations made by the Long-
Term AFC/ATC Task Force.\157\ However, NERC indicates that a
significant amount of work remains before the standard revisions are
considered complete. Since NERC would like to finalize its revised
standards for submittal to the Commission for the summer of 2007, NERC
has established an aggressive schedule of meetings for drafting which
will be coordinated with NAESB.
---------------------------------------------------------------------------

    \157\ Citing Long-Term AFC/ATC Task Force Final Report (Revised
April 14, 2005), available at http://www.nerc.com/~filez/ltatf.html.

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

    219. PJM outlines several guidelines it suggests the Commission
should give to NERC and NAESB regarding the standards development
process and recommends that Commission staff participate in the
standards development process. Williams and EPSA likewise request that
the Commission provide clear guidance to NAESB to assure efficiency and
timeliness of the process.
    220. Some commenters prefer engagement of a fully independent
organization to develop standards and practices related to ATC.\158\
EPSA strongly urges the Commission to require all transmission
providers outside of RTO areas to contract with an independent entity
to develop and/or monitor ATC calculations. Although TDU Systems agree
with EPSA that vertically-integrated transmission providers that are
not subject to the independent oversight of an ISO/RTO retain inherent
incentives to discriminate against competitors, they contend that the
benefit of independent oversight of ATC calculations must be weighed
against the cost of that oversight. Alcoa suggests engaging the
Institute of Electrical and Electronics Engineers (IEEE) instead of the
Commission's proposal to use NERC and NAESB. APPA opposes that
position. New York Commission proposes that regional reliability
organizations, rather than NERC, complete this task and that the ATC
calculators be closely coordinated by

ISOs and RTOs.\159\ PJM contends on reply that New York Commission's
proposal for coordination of ATC between ISOs and RTOs has been
fulfilled at least between PJM and its neighbors, arguing that New York
Commission's proposal is unnecessary and would add a layer of
bureaucracy and cost. TAPS expresses concern with the Commission
proposal to use NERC and encourages the Commission to be precise in its
direction to NERC to accomplish the needed objective.
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    \158\ E.g., Alcoa, Fayetteville, and MISO.
    \159\ If ISOs and RTOs cannot perform the coordination function,
New York Commission suggests the establishment of a Transmission
Oversight Center to oversee the calculation of ATC within and
between ISOs and RTOs.
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Commission Determination
    221. The Commission directs public utilities, working through NERC
and NAESB, to modify the ATC-related reliability standards and business
practices in accordance with specific direction provided in this Final
Rule. As we explain above, the development of a more coherent and
uniform determination of ATC across a region will help limit the
potential for undue discrimination in the calculation of ATC. The
Commission concludes that the NERC reliability standards development
process and the NAESB business practices development process are the
appropriate forums for developing this consistency.
    222. NERC has been certified as the ERO and, as such, has been
found to have the ability to develop reliability standards through
processes with reasonable notice and opportunity for public comment.
NERC's processes are open and provide due process as well as a balance
of interests, while assuring independence from users and owners and
operators of the bulk-power system. Moreover, NAESB has a long history
of developing standard business practices for the electric industry, on
which the Commission has relied in various contexts. While other
entities may bring certain benefits, commenters have not demonstrated
the superiority of IEEE, a regional reliability organization, or a
particular RTO over NERC and NAESB. Once components of ATC are made
consistent and ATC calculation methodologies are made transparent,
opportunities for discretion that may lead to undue discrimination in
the calculation of ATC will be sufficiently eliminated to invalidate
the need for the creation of independent entities to oversee that
calculation. To the extent that, even following the adoption of these
reforms, customers have complaints regarding the calculations performed
by individual transmission owners, they can be addressed on a case-by-
case basis.
    223. With respect to a timeline for completion, the Commission
concurs with NERC that a significant amount of work remains to be done
on ATC-related reliability standards development. We also agree with
the many commenters who state that the NOPR's proposed six-month
timeline is too short for such a complex assignment. Although NERC
projects that it may be able to complete the process by the summer of
2007 (which is approximately six months from the date of the Final
Rule), we believe NERC should have additional flexibility with respect
to its timeline. Accordingly, we direct public utilities, working
through NERC, to modify the ATC-related reliability standards within
270 days after the publication of the Final Rule in the Federal
Register. We also direct public utilities to work through NAESB to
develop business practices that complement NERC's new reliability
standards within 360 days after the publication of the Final Rule in
the Federal Register. Finally, we direct NERC and NAESB to file, within
90 days of publication of the Final Rule in the Federal Register, a
joint status report on standards and business practices development and
a work plan for completion of this task within the timeframe
established above.\160\
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    \160\ NAESB's work plan for developing business practices
related to other reforms adopted in this Final Rule should be filed
separately, as requested in Section IV.C.1.
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c. Applicability to ISOs, RTOs, and Non-Public Utility Transmission
Providers
NOPR Proposal
    224. The Commission did not specifically address the application of
the ATC-related reforms proposed in the NOPR to ISOs and RTOs or non-
public utility transmission providers.
Comments
    225. ISOs and RTOs believe that the Commission should not require
wholesale revisions of RTO and ISO tariffs, even on such issues as ATC
standards.\161\ They caution that many regional grid operators' tariffs
contain nonconforming provisions that were the product of extensive
debate, litigation and settlements. In addition, some commenters point
out that concern about ATC calculations is a non-issue in many ISO/RTO
regions because transmission services in those regions are not based on
physical transmission reservations.\162\
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    \161\ E.g., PJM and MISO Transmission Owners, SPP Reply.
    \162\ E.g., ISO/RTO Council, ISO New England, and Pennsylvania
Commission.
---------------------------------------------------------------------------

    226. MISO argues that AFC calculation methodologies should be
established via the RTO stakeholder process, not NERC. In its reply
comments, Exelon expresses disagreement with MISO and states that there
must be one standard for ATC calculations, not several methods based on
the desires of different sets of stakeholders. Several commenters also
believe that ISOs/RTOs should not be exempt from the requirements for
consistent and transparent ATC calculations.\163\
---------------------------------------------------------------------------

    \163\ E.g., NRECA and TDU Systems.
---------------------------------------------------------------------------

    227. EEI asks the Commission to require all municipal and other
non-public utility transmission providers to adhere to any requirement
for consistent and transparent ATC/AFC calculation. In its view,
applying the ATC-related reforms to these nonjurisdictional entities
would recognize the interconnected nature of the transmission grid. EEI
argues that greater transparency and consistency in the provision of
transmission service would be frustrated if all transmission providers
do not have to comply. Other commenters reply that EEI's concerns are
unfounded and describe an example in the WECC region, where the
methodologies and practices regarding ATC calculations are developed by
representatives from all affected transmission providers, utilities,
and market participants, including nonjurisdictional entities.\164\
---------------------------------------------------------------------------

    \164\ E.g., Lassen and Public Power Council.
---------------------------------------------------------------------------

    228. LPPC contends that the NERC reliability standards related to
ATC calculation will already be applicable to both public and non-
public utilities. LPPC argues that NERC standards, when final, will be
filed with the Commission, become part of the ERO's mandatory
reliability standards and will be fully applicable to otherwise
nonjurisdictional entities. As a result, the ATC standards will be
applicable to and enforceable upon all transmission owners, whether or
not the transmission owner has an OATT.
Commission Determination
    229. We discuss the applicability of the Final Rule to ISOs and
RTOs in section IV.C.2 above. With respect to the application of the
ATC requirements of this Final Rule to municipal and other non-public
utility transmission providers, we likewise note that the applicability
of the rule generally to such entities is addressed in section

IV.C.3. We note here, however, that such entities will be required to
comply with reliability standards developed under FPA section 215. As
LPPC acknowledges, once these reliability standards are approved they
will become part of the ERO's mandatory reliability standards and,
thus, will be applicable to and enforceable upon all transmission
owners, whether or not the transmission owner has adopted the OATT.
d. Alternatives to ATC Consistency
Comments
    230. Some commenters contend that the NOPR is focused too narrowly
on simply improving the consistency and transparency of ATC
determinations and suggest that a focus on balancing (or dispatch)
services and how those are priced would allow the Commission to avoid
the pitfalls inherent in the ATC approach.\165\ In their view, such an
approach would eliminate much of the difference between how third
parties are treated in RTO versus non-RTO systems. Constellation
encourages the Commission to consider requiring transmission providers
to implement all-inclusive, security constrained economic dispatch
processes. In reply comments, Chandley-Hogan argue that the
Commission's ATC-related proposals in the NOPR confuse how transmission
service is actually provided in most of the United States and, as a
result, the Commission's analysis of perceived problems in the
calculation of ATC is flawed, inconsistent with network realities and
the laws of physics, and incompatible with reliable operations.
---------------------------------------------------------------------------

    \165\ E.g., Chandley-Hogan, EPSA, PJM, San Diego G&E, and
Transparent Dispatch Advocates Reply.
---------------------------------------------------------------------------

    231. Contrary to the above claims, some commenters find that ATC
provides a functionally useful measure of available capacity and has
certain advantages over alternative models.\166\ These commenters argue
that the factual record does not support conclusions that bid-based,
marginal cost dispatch by a third party is inherently more efficient or
inherently more likely to remedy undue-discrimination than the OATT
model, and cannot overcome the considerable real world obstacles to
pure economic redispatch, including overlapping and dynamic
constraints, and the physical realities in the Western Interconnection
that often limit the pool of resources that can be redispatched to
solve constraints. LPPC contends that the principal advantage of ATC is
the certainty that it provides for available capacity, suggesting that
the contract path paradigm facilitates long-term bilateral contracting.
---------------------------------------------------------------------------

    \166\ E.g., APPA, CMUA, CPA, Duke, EEI, Entergy, LPPC, Public
Power Council, Sacramento, and WestConnect Reply.
---------------------------------------------------------------------------

Commission Determination
    232. In this rulemaking, the Commission is requiring consistency in
the determination of ATC with the purpose of improving a customer's
ability to receive transmission service on a non-discriminatory basis.
These reforms are fully consistent with operational reality, and we
decline to mandate the security constrained economic dispatch
alternative proposed by Chandley-Hogan. Chandley-Hogan argue that it
would be unduly discriminatory to exclude third-party generators from
an efficient dispatch to serve native load and therefore a centralized,
bid-based market is required. We agree that a centralized bid-based
market can benefit customers and, over a large region, can manage
congestion efficiently. We do not believe, however, that mandating that
result--essentially requiring that Day 2 RTOs be adopted in every
region of the country--is necessary to remedy undue discrimination in
the provision of transmission service. The concern raised by Chandley-
Hogan is not related solely to the nondiscriminatory use of the
transmission system. It also implicates the purchase decisions of
transmission providers on behalf of their native load customers. These
decisions are regulated primarily by the states and we decline to take
generic action in this rulemaking to reform the processes by which
those purchases are made.
e. ATC Components
    233. The next several sections address components of ATC that must
be made consistent to remove the potential for undue discrimination,
namely TTC/TFC, ETC, CBM, and TRM.
(1) Total Transfer Capability (TTC)/Total Flowgate Capability (TFC)
NOPR Proposal
    234. The Commission proposed to direct public utilities, working
through NERC, to develop consistent practices for calculating total
transfer/flowgate capability (TTC/TFC). Although the NERC reliability
regions have historically calculated transfer capability using
different approaches, the Commission expressed its view that guidelines
for a common approach to calculating transfer capability are
achievable. The Commission also stated that the criteria used for
identifying flowgates and determining TFC could be more consistent.
Comments
    235. Entergy supports the development of consistent practices for
determining transfer capability while maintaining flexibility to
recognize regional and system-specific differences. APPA agrees that
the calculation of TTC/TFC is, for the most part, a regional
calculation. APPA states that the Western Interconnection and ERCOT use
their own methods, which are generally applied system-wide. APPA
believes that more standardization and coordination of TTC/TFC among
transmission providers in the Eastern Interconnection, where two
primary methods are used to calculate TTC or TFC, would be desirable
because of reported loop-flow problems in the Eastern Interconnection.
    236. In order to increase transfer capability from existing
facilities, AWEA proposes that the Commission direct NERC, as part of
developing consistent ATC standards, to investigate the impact of
implementing dynamic line ratings in TTC/TFC calculations and propose
protocols to effectuate such a program. In response to AWEA's proposal,
commenters state that if the Commission decides to provide guidance to
NERC with regard to dynamic line ratings, the Commission should
encourage NERC to develop standards with regard to dynamic line ratings
in the operating horizon, but not in the planning horizon.\167\
---------------------------------------------------------------------------

    \167\ E.g., MAPP and MidAmerican.
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Commission Determination
    237. The Commission adopts the NOPR proposal and directs public
utilities, working through NERC, to develop consistent practices for
calculating TTC/TFC. We direct public utilities, working through NERC,
to address, through the reliability standards process, any differences
in developing TTC/TFC for transmission provided under the pro forma
OATT and for transfer capability for native load and reliability
assessment studies.
    238. We acknowledge that reliability regions have historically
calculated transfer capability using different approaches, and we agree
that regional differences should be respected.\168\ However, as already
discussed above regarding ATC, the TTC requirements will be determined
by the NERC reliability standards and any request for a regional
difference from the reliability standards must take place through the
NERC process.
---------------------------------------------------------------------------

    \168\ For example, WECC has a documented open process for
establishing TTC for the Western Interconnection.

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

    239. With respect to AWEA's proposal regarding implementing dynamic
line ratings in TTC/TFC calculations, the Commission finds that this
proposal is outside the scope of this rulemaking as it does not appear
to relate to undue discrimination in transmission service and, in any
event, would best be addressed in the first instance through the NERC
reliability standards development process, addressing reliability
standards that regulate facility ratings. If AWEA desires to pursue
this proposal, it should propose an appropriate dynamic line rating
standard within the ERO's reliability standards development process.
(2) Existing Transmission Commitments (ETC)
NOPR Proposal
    240. In the NOPR, the Commission expressed its view that the lack
of consistency in modeling of existing transmission commitments (ETC)
resulted in excessive discretion in determining how much capacity a
transmission provider sets aside for native load, including its network
customers. The Commission therefore proposed the development of a
consistent methodology for determining the capacity needed and set
aside for native load usage. The Commission also proposed that
accounting for transmission reservations in an ATC/AFC calculation be
more consistent. The Commission further proposed that public utilities,
working through NERC, establish and specifically identify the
reservations to be used in determining ETC.
Comments
    241. Entegra and PGP support increasing consistency in determining
ETC. APPA agrees that it would be helpful to standardize the method of
accounting for ETC on an interconnection-wide basis. APPA states,
however, that flexibility might be required among the interconnections.
TDU Systems requests that the Commission define with specificity the
types of transmission service requests or scheduled transmission
transactions that should be included in ETC and agrees with the
Commission that inclusion of all requests for transmission service in
ETC is likely to overstate usage of the system, thus understating ATC.
It suggests that the Commission develop a bright line method for
calculating ETC. NERC notes that its proposed reliability standards
would define ETC and require appropriate documentation. NERC adds,
however, that the components included in ETC appear to be candidates
for business practices rather than reliability standards.
    242. Williams proposes that ETC be the subject of an expanded
definition and that native load growth projections be based on
verifiable data provided by an independent source. It also states that
transmission providers should be required to update ATC based on each
confirmed transmission service reservation (point-to-point or network,
firm or non-firm).
Commission Determination
    243. To achieve greater consistency in ETC calculations and further
reduce the potential for undue discrimination, the Commission adopts
the NOPR proposal and directs public utilities, working through NERC
and NAESB, 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 NERC will address
ETC through the MOD-001 reliability standard rather than through a
separate reliability standard.\169\ By using MOD-001, the ETC
calculation can be adjusted to be applicable to each of the three ATC
methodologies under development by NERC.
---------------------------------------------------------------------------

    \169\ The purpose of MOD-001 is to promote the consistent and
uniform application of transfer capability calculations among the
transmission system users.
---------------------------------------------------------------------------

    244. In order to provide specific direction to public utilities and
NERC, 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)
appropriate point-to-point reservations,\170\ (4) rollover rights
associated with long-term firm service, and (5) other uses identified
through the NERC process. ETC should not be used to set aside transfer
capability for any type of planning or contingency reserve, which are
to be addressed through CBM and TRM.\171\ In addition, in the short-
term ATC calculation, all reserved but unused transfer capability (non-
scheduled) shall be released as non-firm ATC.
---------------------------------------------------------------------------

    \170\ By ``appropriate,'' we mean that reservations accounted
for under ETC depend on the firmness and duration of the
reservation. The specific characteristics should be developed in the
reliability standard.
    \171\ TRM also includes such things as loop flow and parallel
path flow.
---------------------------------------------------------------------------

    245. We agree with TDU Systems that inclusion of all requests for
transmission service in ETC would likely overstate usage of the system
and understate ATC. We therefore 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 POR. This will
prevent overly unrealistic utilization of transmission capacity
associated with power output from a generator identified as a POR. We
direct public utilities, working through NERC, to develop requirements
in MOD-001 that lay out clear instructions on how these reservations
should be accounted. One approach that could be used is examining
historical patterns of actual reservation use during a particular
season, month, or time of day.
    246. We agree with NERC that some elements of ETC are candidates
for business practices rather than reliability standards. Accordingly,
we direct public utilities, working through NAESB, to develop business
practices necessary for full implementation of the developed MOD-001
reliability standard.
    247. We decline to adopt Williams's proposal to require that native
load growth be based on the verifiable data provided by an independent
source. Through increased consistency and transparency of ATC
determinations, including requirements for posting additional data,
third parties will be able to verify the accuracy of ETC, helping to
eliminate opportunities for undue discrimination.
(3) Capacity Benefit Margin (CBM)
NOPR Proposal
    248. In the NOPR, the Commission proposed three options to address
the CBM component of ATC: (1) Have NERC develop clear standards for how
the CBM value should be determined, allocated across transmission
paths, and used; (2) charge an entity for which transfer capability has
been set aside to meet generation reliability criteria a separate rate
for this service; or (3) eliminate CBM and require an entity reserving
ATC to meet generation reserve (currently through CBM) to designate
network resources on the other side of the interface and make an
associated transmission service reservation.
Comments
    249. Numerous commenters support the Commission's proposed option
one, requiring NERC to develop clear standards for how the CBM value
should be determined, allocated across

transmission paths, and used.\172\ They believe that CBM ensures the
ability to import needed power to support system conditions. TVA argues
that option two would be costly and may cause some systems to forego
CBM, thereby jeopardizing service to native load customers. PJM states
that option two is irrelevant in PJM since PJM ``totals'' reservations
and decides when CBM can be used. Supporters of option one criticize
option three, elimination of CBM, as costly and a threat to
transmission system reliability. Southern, Progress Energy, and PJM
emphasize that, without CBM, the LSEs would need to increase their
reserve margin by contracting for additional generation capacity,
costing millions of dollars. In addition, Ameren and TVA believe that
CBM elimination will increase the likelihood of widespread blackouts in
emergency conditions.
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    \172\ E.g., Allegheny, Ameren, EEI, Duke, NRECA, TVA, APPA,
Bonneville, EPSA, FirstEnergy, Indianapolis Power, MidAmerican,
Pinnacle, PJM, PGP, PNM-TNMP, Public Power Council, Sacramento,
Seattle, South Carolina E&G, TANC, TDU Systems, and Wisconsin
Electric.
---------------------------------------------------------------------------

    250. At the October 12 Technical Conference, Exelon supported
option two proposing a charge for CBM. Exelon contended that, in a
rate-making context, there would be an increase in the divisor of the
rate by the amount of CBM set-aside which would lower the point-to-
point charge. Consequently, those not benefiting from the CBM set-aside
effectively would be paying a lower charge.
    251. Constellation and Morgan Stanley support the elimination of
CBM and argue that CBM and TRM are often used interchangeably and
result in duplicative transmission set-asides. They also argue that
there is no compelling need for CBM in the current liquid market
environment. In addition, Morgan Stanley states that LSEs affiliated
with the transmission provider should not be allowed to use CBM for
long-term planning purposes as an excuse to avoid undertaking needed
resource additions or to conceal the true cost of their load serving
functions. Furthermore, the Commission should not be distracted by
assertions that such long-term arrangements are necessary for
``reliability,'' when in fact they are simply a way to protect the
economic interests of a particular entity.
    252. Duke replies that Constellation mistakenly believes that CBM
is currently only available to a transmission provider's native load
when, in fact, for those transmission providers that establish CBM, it
should be established for the load of all LSEs in the control area.
Duke contends that not all transmission providers set aside capacity
through CBM for their native load; to the extent that a transmission
provider does not set aside CBM, there should be no obligation to allow
other LSEs to do so. Duke proposes that the Commission should continue
to permit such flexibility.
    253. NERC takes no position on CBM, expecting that the issue can be
settled through the NERC and NAESB Procedure for Joint Standards
Development and Coordination and through other open forums.
    254. TAPS suggests that the Commission ensure that all LSEs have
both access to CBM to meet their reserve-sharing needs and meaningful
input into how much CBM is reserved. To do so, TAPS recommends the
creation of a reserve-sharing group made up of the transmission
provider and LSEs it serves. It argues that this would remove
reservation decisions from the sole discretion of the vertically-
integrated transmission provider and instead have them made by the
transmission provider/LSE reserve-sharing group, subject to dispute
resolution at the Commission. All LSEs would be invited to participate
in the studies as well as review the results and assumptions. Moreover,
once a regional planning process is established, as proposed in the
NOPR, TAPS recommends that the regional planning group be required to
approve the CBM reservation as well.
    255. Williams suggests that a transmission provider must designate
network resources and reserve firm transfer capability on both sides of
the control area transmission interface in order to reserve CBM. Duke
replies that, although some commenters prefer eliminating CBM and
replacing it with additional designated network resources, CBM is the
preferable option because it is less costly. Duke further argues that
the choice is between setting aside both additional transmission and
generation capacity to deal with emergencies (the additional designated
network resource approach) versus setting aside only transmission (the
CBM approach). Having to procure additional designated network
resources to keep in reserve reduces one of the main benefits of
interconnected operations. Duke argues that eliminating CBM would drive
up costs for network customers, as they would have to procure
additional generation and transmission resources. EEI adds that such a
proposal may result in increased LSE reserve requirements, over-
building of generation supply, and a reduction, rather than an
increase, in ATC.
Commission Determination
    256. The Commission concludes that it is appropriate to allow LSEs
to retain the option of setting aside transfer capability in the form
of CBM to maintain their generation reliability requirement. We agree
with commenters that, without CBM, LSEs would have to increase their
generation reserve margins by contracting for generation capacity,
which may result in higher costs without additional reliability
benefits. We require, however, the development of standards for how CBM
is determined, allocated across transmission paths, and used in order
to limit misuse of transfer capability set aside as CBM. Transmission
providers also must reflect the set-aside of transfer capability as CBM
in the development of the rate for point-to-point transmission service
to ensure comparable treatment for point-to-point to customers.
    257. The Commission therefore adopts a combination of the NOPR
options one and two, and declines to adopt option three. First, we
require public utilities, working through NERC and NAESB, to develop
clear standards for how the CBM value shall be determined, allocated
across transmission paths, and used. We understand that NERC has
already begun the process of modifying several of the CBM-related
reliability standards and that the drafting process is a joint project
with NAESB. Second, we require transmission providers to reflect the
set-aside of transfer capability as CBM in the development of the rate
for point-to-point transmission service.
    258. We note that there is broad concern that eliminating CBM
(option three) would impose extraordinary costs for meeting generation
reliability criteria, which then may lead utilities to reduce their
generation reliability requirement to avoid the cost increase. We
believe that the reforms reflected in combining options one and two are
sufficient to remedy undue discrimination and that the adverse effects
associated with option three are neither warranted nor required. We
reject Morgan Stanley's call for CBM elimination on the grounds that
CBM is acting as a disincentive to undertake needed generation resource
additions. It would be inappropriate for the Commission to restrict the
ability of an LSE to determine how best to meet its generation
reliability criteria.
    259. To ensure CBM is used for its intended purpose, CBM shall only
be used to allow an LSE to meet its generation reliability criteria.
Consistent with Duke's statement, we clarify that

each LSE within a transmission provider's control area has the right to
request the transmission provider to set aside transfer capability as
CBM for the LSE to meet its historical, State, RTO, or regional
generation reliability criteria requirement such as reserve margin,
loss of load probability (LOLP), the loss of largest units, etc.
    260. We direct public utilities, working through NERC, to develop
clear requirements for allocating CBM over transmission paths and
flowgates. While we do not mandate a particular methodology for
allocating CBM to paths and flowgates, one approach could be based on
the location of the outside resources or spot market hubs that an LSE
has historically relied on during emergencies resulting from an energy
deficiency.
    261. We concur with TAPS' proposal that all LSEs should have access
to CBM and meaningful input into how much transfer capability is set
aside as CBM. In the transparency section below, we provide detailed
requirements regarding availability of documentation used to determine
the amount of transfer capability to be set aside as CBM and the
posting of CBM values and narratives. Access to this documentation will
enable LSEs to validate how much transfer capability is set aside as
CBM on each system and provide them with information to question
whether the set-aside is consistent with the reliability standards and
this Final Rule.
    262. Concerning TAPS' proposal to remove the reservation decision
from the sole discretion of transmission providers, we determine that
LSEs should be permitted to call for use of CBM, if they do so pursuant
to conditions established in the reliability standards development
process. We direct public utilities working through NERC to modify the
CBM-related standards to specify the generation deficiency conditions
during which an LSE will be allowed to use the transfer capability
reserved as CBM. In addition, we direct that transmission set aside as
CBM shall be zero in non-firm ATC calculations. Finally, we order
public utilities to work with NAESB to develop an OASIS mechanism that
will allow for auditing of CBM usage.
    263. We also require transmission providers to design their
transmission charges to ensure that the class of customers not
benefiting from the CBM set-aside, i.e., point-to-point customers, do
not pay a transmission charge that includes the cost of the CBM set-
aside. To do this, transmission providers are required to submit
redesigned transmission charges that reflect the CBM set-aside through
a limited issue FPA section 205 rate filing as part of its initial ATC-
related compliance filing. These filings, which may be submitted within
120 days after the publication of the Final Rule in the Federal
Register, may be limited to the rate design change only, i.e., they
will not require the submission of cost of service data or a revision
to the transmission provider's revenue requirement.
    264. With respect to TAPS' proposal that all LSEs should be allowed
to use CBM to meet their reserve-sharing needs, we believe that TRM is
the appropriate category for that purpose, not CBM. We reject TAPS'
proposal to use CBM for the LSE's reserve-sharing needs, but instead
make TRM available for the incremental power flows resulting from
reserve sharing, as explained next.
    265. As we are rejecting option three, which would have required
the reservation of transfer capability rather than using CBM, we also
reject Williams' proposal to require the reservation of transfer
capability on both sides of an interface for CBM.
(4) Transmission Reserve Margin (TRM)
NOPR Proposal
    266. Finally, the Commission proposed the development of
reliability standards MOD-008 and MOD-009 \173\that specify the
uncertainties that TRM could be used to accommodate, which could
include (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, including
intermittent resources, (6) automatic sharing of reserves, and (7)
other uncertainties identified through the NERC reliability standards
development process.
---------------------------------------------------------------------------

    \173\ The MOD-008 and MOD-009 reliability standards document
regional TRM methodologies and procedures for verifying TRM values.
---------------------------------------------------------------------------

Comments
    267. Most commenters agree that the existing definitions for TRM
require clarification.\174\ Commenters also agree that NERC should be
required to develop clear standards for the determination of TRM,
including specifying the criteria used in the determination of
TRM.\175\ PNM-TNMP supports the Commission's proposal, pointing out
that the implementation of the current NERC standards definition for
TRM and CBM could result in its double-counting, which must be
eliminated. APPA members in the Western Interconnection suggest that
regional variations be permitted. They also note that the modeling
methods used by WECC and its sub-regions may differ from those used in
the Eastern Interconnection. For example, they contend that
uncertainties associated with transmission maintenance schedules that
are driven by hydro-production curves will seasonally affect TRM set-
asides on certain transfer paths. PJM believes that the TRM methodology
should be consistent at the regional reliability organization level.
PJM also contends that TRM should be coordinated, exchanged and
respected on external flowgates and that the concept of a maximum TRM,
by percentage, should be adopted in the NERC standards.
---------------------------------------------------------------------------

    \174\ E.g., Allegheny, APPA, EEI, EPSA, Exelon, LPPC,
MidAmerican, NRECA, Northwest IOUs, NorthWestern, Occidental,
Pinnacle, Powerex, PNM-TNMP, PPL, PJM, PPM, and WestConnect.
    \175\ Exelon recommends that the following factors should be the
same for the planning process and ATC/AFC process to achieve
consistency: base case flows, reservation impacts, TRM and CBM
forecasted to occur simultaneously; counterflows; positive impacts
resulting from reservations and generation dispatch; TRM for the
same scenarios; and CBM.
---------------------------------------------------------------------------

    268. Consistent with its position on CBM, TAPS proposes that TRM
set-asides should be conditioned on inclusive reserve-sharing
arrangements, with the reservations determined by the reserve-sharing
group, subject to dispute resolution before the Commission (and,
eventually, approval by joint planning groups).
    269. PNM-TNMP suggests that the Commission consider definitions to
include the following clarification taken from WECC procedures on ATC:
``If the limitation on the use of TRM to 59 minutes would force a
Transmission Provider to set aside unnecessary CBM on the same path as
the TRM, that Transmission Provider may utilize the TRM beyond the 59
minutes.'' \176\ PNM-TNMP states that this would allow the transmission
provider to maximize the ATC by not needlessly setting aside twice the
amount of transmission (TRM and CBM) than is necessary for reliability.
---------------------------------------------------------------------------

    \176\ Citing WECC Rocky Mountain Operating and Planning Group,
Determination of Available Transfer Capability within the Western
Interconnection, June 2001, page 9, http://www.wecc.biz/modules.php?op=modload&name=Downloads&file=index&req=getit&lid=1035
.

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

    270. Nevada Companies argue that no new standards are required for
TRM and that any further action would be burdensome. They explain that
NERC has a well-established definition that does not require further
clarification. In their view, all that is required is a complete
statement, to be posted on OASIS, regarding the transmission provider's
application of TRM. NERC

comments that the existing reliability standards for TRM will be
revised to require clear documentation of the calculation of TRM. It
also adds that the revised standard will make various TRM components
mandatory to achieve more consistency across methodologies.
    271. Santee Cooper urges the Commission to ensure that service to
native load and transmission system reliability will not be compromised
as the Commission seeks greater levels of consistency in the
calculation of ATC. It states that the Commission also must be
cognizant of the importance of TRM in the provision of service to
native load.
Commission Determination
    272. The Commission adopts the NOPR proposal and requires public
utilities, working through NERC, to complete the ongoing process of
modifying TRM standards MOD-008 and MOD-009. We understand that the
standard drafting process is underway as a joint project with NAESB.
    273. The Commission also adopts the NOPR proposal to establish
standards specifying the appropriate uses of TRM to guide NERC and
NAESB in the drafting process. Transmission providers may set aside TRM
for (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
sharing of reserves, and (7) other uncertainties as identified through
the NERC reliability standards development process. Because load,
facility loading and other uncertainties constantly deviate, we will
not require that TRM set aside capacity be set at zero in the non-firm
ATC calculation. In other words, we will not require transfer
capability that is set aside as TRM to be sold on a non-firm basis. We
find that clear specification in this Final Rule of the permitted
purposes for which entities may reserve CBM and TRM will virtually
eliminate double-counting of TRM and CBM.
    274. We will not adopt PNM-TNMP's proposal regarding use of set
aside transfer capability as TRM beyond 59 minutes, rather than
converting it to CBM. Our proposal is to separate transfer capability
set asides as either CBM or TRM without regard to duration of use of
the set aside. Therefore, such a clarification is not necessary.
    275. In addition, we direct public utilities, working through NERC,
to establish an appropriate maximum TRM. One acceptable method may be
to use a percentage of ratings reduction, i.e., model the system
assuming all facility ratings are reduced by a specific percentage.
This is a relatively simple method and, if adopted as the reliability
standard's method, should not restrict a transmission provider from
using a more sophisticated method that may allow for greater ATC
without reducing overall reliability.
    276. Because of the operational characteristics of the
uncertainties that are to be accommodated using TRM, and their
aggregate impact on reliable operation, we require each transmission
provider to calculate, and allocate on the paths and flowgates, the
aggregate TRM value for all LSEs within its area. We support NERC's
plan to revise existing reliability standards for TRM to require clear
documentation of the TRM calculation, as we expect the TRM value to be
supported and fully transparent. In addition, we require each
transmission provider to make available all underlying documentation,
including work papers and load flow base cases, used to determine TRM,
to any transmission customer and LSE within its control area, subject
to a confidentiality agreement,\177\ if necessary. We agree with Santee
Cooper's comments that the Commission must ensure that service to
native load and system reliability are not compromised. We believe that
our requirement for public utilities to work through NERC satisfies
such concerns.
---------------------------------------------------------------------------

    \177\ The agreement may appropriately restrict the sharing of
sensitive information with customer personnel that are involved only
in transmission functions, as opposed to merchant functions.
---------------------------------------------------------------------------

    277. With respect to the proposal to permit regional variations in
the TRM calculation methodology, we reiterate our position stated above
that any request for regional difference from the applicable
reliability standards must take place through the NERC reliability
standards development process. With respect to TAPS' proposal regarding
reserve sharing groups, we clarify that, to the extent transfer
capability is needed for transmission of shared reserves, this is
included under TRM. However, as noted previously in the CBM discussion,
we are not mandating the use of reserve sharing groups.
f. Modeling, Assumptions and Input Data
NOPR Proposal
    278. The Commission's proposal with regard to modeling, assumptions
and data inputs was based on a principle that there should be
consistency among transmission providers and between what the
transmission provider does for its operation and expansion planning for
native load and what it does in determining short and long-term ATC for
all uses. The Commission stated its view that consistency is necessary
to ensure non-discriminatory treatment by eliminating a transmission
provider's ability to use discretion to the disadvantage of
competitors. The Commission proposed three specific areas for reform.
    279. First, the Commission proposed to require public utilities,
working through NERC, to modify the ATC-related standards to
incorporate a requirement for periodic validation and modification of
models to ensure that they are up to date.\178\ The Commission stated
that the models should be updated and benchmarked to actual events.
---------------------------------------------------------------------------

    \178\ The Commission noted that this would include review of
load flow base cases, short circuit data, transient and dynamic
stability simulation data, contingency (files should contain
information on special protection schemes and remedial action plans)
subsystem and monitoring files, and production cost models.
---------------------------------------------------------------------------

    280. Second, the Commission proposed that, to the maximum extent
practicable, the same data must be used by the transmission provider to
determine short- and long-term ATC as those used in system operation
and planning studies, respectively.
    281. Third, the Commission proposed that public utilities, working
through NERC, develop assumptions for use in ATC determinations and
that the assumptions remain consistent among transmission providers to
the maximum extent practicable. The Commission indicated that short-
and long-term ATC calculations should be developed using consistent
assumptions regarding representative load levels, generation dispatch,
transmission reservations and counterflows, in addition to any other
modeling assumptions identified by NERC. The Commission further
proposed that there should be a consistent approach to the modeling of
load levels, a method established for determining which generators
should be modeled in service (including guidance on how independent
generators should be considered), consistency in the simulation of
power flows from points of receipt to delivery when sources are
unknown, and consistency in the manner in which ATC/AFC reservations
are accounted for. The Commission stated that the model for long-term
ATC should include, to the maximum extent practicable, the same
assumptions regarding new transmission and generation facilities
additions and retirements as those used in planning for expansion.
    282. The Commission noted that the proposal is not intended to
change the manner in which native load is served

and sought comment on whether (and, if so, how) this proposal would
affect service to native load customers.
Comments
    283. Commenters generally discuss consistency of data, assumptions
and modeling together so we in turn do the same. Many commenters
support the proposals for consistency in data, assumptions and/or
modeling.\179\ Others support flexibility or regional variation.\180\ A
few commenters oppose specific aspects of the overall proposal.\181\
---------------------------------------------------------------------------

    \179\ E.g., APPA, Arkansas Commission, Constellation, Entegra,
Exelon, EPSA, ISO/RTO Council, LDWP, MidAmerican, Municipals, NRECA,
CREPC, Sacramento, Santee Cooper, Suez Energy NA, TAPS, TDU Systems,
WestConnect, and Williams.
    \180\ E.g., Bonneville. Santee Cooper, and Entergy.
    \181\ E.g., PJM, EPSA, and Ameren.
---------------------------------------------------------------------------

    284. TDU Systems and Sacramento express support for the
Commission's proposal to require public utilities, working through
NERC, to develop modeling assumptions for use in calculating ATC that
are consistent with those used to plan the operation and expansion of
the transmission system. Xcel, however, would have the Commission go
further. Xcel recommends that the Commission enhance its proposal by
establishing a date certain for transmission providers in the Western
Interconnection to be required to account for impacts of loop flows
when processing transmission service requests and calculating ATC. Xcel
suggests that NERC be directed to develop standards for evaluation of
counterflows on ATC. EPSA offers examples of specific data inputs that,
in its view, should also be standardized among all transmission
providers, which include: Load levels and distribution studies;
transmission outages; generation outages; and generation dispatch.
Ameren submits that any modeling of base generation dispatch must model
generators, including merchant generators, as they are expected to run.
    285. Williams asks the Commission to require consistency between
transmission planning horizon and procurement terms, and transparency
around the long-term transmission planning assumptions. Williams states
that third-party bids to a request for proposals are evaluated with
transmission costs that may already be included in long-term
transmission plans. Thus, argues Williams, procurement and long-term
planning assumptions are intertwined. In reply, Entergy acknowledges
and agrees that the models used for planning, operations and service
request evaluations should generally be based on similar data and
procedures, but argues that due to changes in system configuration,
facilities included in transmission plans are often not needed at all
and thus are not constructed. Therefore, Entergy proposes that the
Commission allow NERC to determine the circumstances under which
differences between models would be appropriate.
    286. Southern asks for clarification on what the Commission intends
by proposing that modeling assumptions be consistent in the context of
TTC assessments. Southern explains that, as the Commission has
recognized, the inevitable changes in system conditions between
different time horizons (e.g., real-time and planning and operations)
would render this approach unreliable because load levels, dispatch
arrangements, reservations, and outages cannot be the same over
significantly different time horizons.
    287. Supporting regional differences, Bonneville contends that
calculating ATC for a hydroelectric system requires different inputs
and modeling assumptions than are appropriate for thermal-based
systems. Bonneville explains that non-power constraints placed on
hydroelectric projects that were built for multiple uses are a major
concern on the Bonneville system. Consequently, hydro operators are
more limited in their ability to use generation redispatch as a tool to
meet long-term firm load obligations. Similarly, Santee Cooper cautions
that over-standardization may result in certain parameters being
misstated or inappropriately constrained, resulting in inaccurate
reservations of capacity for native load purposes and a potentially
detrimental effect on the reliability of service. It recommends that
the Commission direct NERC to allow deviations from the standard
modeling assumptions where the need can be supported, with the caveat
that a utility's modeling assumptions must be transparent and available
for scrutiny. Seattle contends that modeling assumptions should be
developed at the sub-regional level, consistent among adjacent
transmission providers. TVA suggests that the transmission providers be
allowed to retain flexibility to conduct risk analyses and reflect
those in their modeling assumptions.
    288. Other commenters argue that modeling assumption
standardization should not be performed by NERC and, instead, should be
delegated to the regional reliability organizations or RTOs, as they
possess a superior knowledge of the physical grid within their
boundaries.\182\ PJM states that such issues are best left to the joint
stakeholder processes and the resulting joint and common market
initiatives.
---------------------------------------------------------------------------

    \182\ E.g., Sacramento, Manitoba Hydro, Nevada Companies, and
TANC.
---------------------------------------------------------------------------

    289. In response to the Commission's inquiry as to how
standardizing the modeling assumptions and data would affect native
load, commenters generally state that standardization of ATC modeling
assumptions would increase comparability of service to LSEs and enhance
the ATC methodology and its nondiscriminatory application to grid
utilization.\183\
---------------------------------------------------------------------------

    \183\ E.g., Sacramento.
---------------------------------------------------------------------------

Commission Determination
    290. The Commission directs public utilities, working through NERC,
to modify the reliability standards MOD-010 through MOD-025 \184\ to
incorporate a requirement for the periodic review and modification of
models for (1) Load flow base cases with contingency, subsystem, and
monitoring files, (2) short circuit data, and (3) transient and dynamic
stability simulation data, in order to ensure that they are up to date.
This means that the models should be updated and benchmarked to actual
events. We find that this requirement is essential in order to have an
accurate simulation of the performance of the grid and from which to
comparably calculate ATC, therefore increasing transparency and
decreasing the potential for undue discrimination by transmission
providers.
---------------------------------------------------------------------------

    \184\ The MOD-010 through MOD-025 reliability standards
establish data requirements, reporting procedures, and system model
development and validation for use in the reliability analysis of
the interconnected transmission systems.
---------------------------------------------------------------------------

    291. We note that commenters generally were very supportive of the
Commission's proposals for review and update of models and for
consistency of assumptions and data inputs. We received no adverse
comments concerning our general proposal to require public utilities,
working through NERC, to modify the ATC-related standards to
incorporate a requirement for the periodic review and modification of
models to ensure that they are up to date. Moreover, the need to
improve the quality of system modeling was one of the U.S.-Canada Power
System Task Force recommendations.\185\
---------------------------------------------------------------------------

    \185\ Final Report on the August 14, 2003 Blackout in the United
States and Canada: Causes and Recommendations.
---------------------------------------------------------------------------

    292. The Commission also adopts the NOPR proposal to require
transmission providers to use data and modeling assumptions for the
short- and long-term ATC calculations that are consistent with that
used for the

planning of operations and system expansion, respectively, 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 facilities additions and retirements, and
(8) counterflows. We find that requiring consistency in the data and
modeling assumptions used for ATC calculations 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. The Commission
directs public utilities, working through NERC, to modify ATC standards
to achieve this consistency.
    293. With regard to EPSA's request for the standardization of
additional data inputs, we believe they are already captured in the
Commission's proposal as adopted in this Final Rule. Xcel asks the
Commission to require consistency in the determination of counterflows
in the calculation of ATC. Counterflows are included in the list of
assumptions that public utilities, working through NERC, are required
to make consistent. We believe that counterflows, if treated
inconsistently, can adversely affect reliability and competition,
depending on how they are accounted for. Accordingly, we reiterate that
public utilities, working through NERC and NAESB, are directed to
develop an approach for accounting for counterflows, in the relevant
ATC standards and business practices. We find unnecessary Xcel's
request that we require a date certain for specific issues in the
Western Interconnection to be addressed. Above we require public
utilities, working through NERC, to modify the ATC standards within 270
days after the publication of the Final Rule in the Federal Register.
    294. With regard to Williams' request that the Commission require
consistency between transmission planning horizons and procurement
terms, we believe that such an express requirement is neither
appropriate nor necessary. The manner in which transmission providers
procure power for native load customers is generally outside the scope
of this rulemaking. This notwithstanding, we note that by this Final
Rule, Williams and other affected market participants will have an
opportunity to participate in a transmission provider's coordinated,
regional planning process. This will provide a vehicle for interested
parties to gain access to planning-related information and to have
their own plans for transmission evaluated at the same time the
transmission provider plans for its needs. Coupled with the
modifications to the ATC-related reliability standards that require the
same data and assumptions to be used for calculating long-term ATC as
in system planning, these reforms are adequate to address Williams'
concern. To the extent there are changes on the system, these should be
captured in the regional transmission planning process and in the
determination of ATC. We therefore reject Entergy's proposal to allow
NERC to determine the circumstances under which differences between
models would be appropriate in order to ensure comparable service for
all transmission customers.
    295. We offer the following clarifications. In response to
Southern, 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 or approach to determining load levels. 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 of approach, it is imperative that all transmission providers
use the same approach to modeling load levels to enable the meaningful
exchange of data among transmission providers. Accordingly, we direct
public utilities, working through NERC, to develop consistent
requirements for modeling load levels in MOD-001 for the services
offered under the pro forma OATT.
    296. With respect to modeling of generation dispatch, we direct
public utilities, working through NERC, to develop requirements in
NERC's MOD-001 reliability standard specifying how transmission
providers shall determine which generators should be modeled in
service, including guidance on how independent generation should be
considered. We agree with Ameren that any modeling of base generation
dispatch must model generators, including merchant generators, as they
are expected to run. Accordingly, we direct public utilities, working
through NERC, to revise reliability standard MOD-001 by specifying that
base generation dispatch will model (1) All designated network
resources and other resources that are committed or have the legal
obligation to run, as they are expected to run and (2) uncommitted
resources that are deliverable within the control area, economically
dispatched as necessary to meet balancing requirements.
    297. Regarding transmission reservations modeling, we direct public
utilities, working through NERC, to develop requirements in reliability
standard MOD-001 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.
    298. In response to commenter requests in favor of flexibility and
regional differences, we again require that any waivers from the
approved NERC reliability standards must take place through the NERC
reliability standards process as a request for regional difference.
Also, we disagree with commenters who argue that modeling assumptions
should be delegated to regional reliability organizations. The goal of
this rulemaking is to increase consistency in ATC calculations and that
is best accomplished through NERC, which has established processes to
address requests for regional differences from the reliability standard
requirements. We conclude that the NERC process is appropriate as it is
open to all industry participants and, therefore, is a suitable arena
for establishment of common standards for modeling assumptions.
g. ATC Calculation Frequency
NOPR Proposal
    299. The Commission proposed the development of standards requiring
that the ATC calculation be performed with consistent frequency among
transmission providers. Specifically, the Commission proposed that
transmitting public utilities, working through NERC and NAESB, develop
standards requiring that the calculation be performed 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 forecast, interchange
schedules, transmission reservations, facility ratings, and other
necessary data. The Commission also supported uniform updating of ATC
values and its components (e.g., TTC, ETC, CBM, and TRM).
Comments
    300. Alcoa and Powerex emphasize the critical need for ATC to be
calculated more frequently for

constrained facilities. On constrained paths, where transmission
equipment is stressed to its limits, Alcoa recommends that ATC be
calculated on an hourly or real-time basis and be adjusted for
temperature extremes. Seattle comments that ATC should be updated on a
``by exception'' basis, i.e., when significant model changes or
confirmations of service requests occur. While supporting the
Commission proposal, TAPS cautions against updating ATC/AFC too
frequently, as this may play into the hands of those who use
reservation computer programs.
Commission Determination
    301. The Commission adopts the NOPR proposal and requires the
development of reliability standards that ensure ATC is calculated at
consistent intervals among transmission providers. The Commission thus
directs public utilities, working through NERC and NAESB, to revise
reliability standard MOD-001 to require ATC to be recalculated 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 forecast, 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. ATC-related
requirements for OASIS posting are discussed below.
h. Data Exchange
NOPR Proposal
    302. The Commission proposed the development through NERC of
standard protocols that would enable and require the exchange of data
and coordination among transmission providers. The Commission proposed
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. The Commission expressed its view that significant
improvements in the communication, coordination, and exchange of data
across all transmission providers in an interconnection are needed to
produce accurate determinations of ATC. The Commission sought comment
as to how much data sharing is workable, whether there are additional
data that should be provided, whether access to such data should be
limited to transmission providers, and if there are existing forums by
which these or similar data are already shared.
Comments
    303. Most commenters support the Commission's proposal to establish
rules for data exchange, but express a preference for confidential data
exchange.\186\ NERC states that proposed changes to its existing
modeling standards would require transmission providers to coordinate
the calculation of TTC/ATC/AFC with others. TVA emphasizes that it has
already incorporated these principles into its operating processes by
executing agreements that provide for data exchange and coordination
with neighboring transmission systems.
---------------------------------------------------------------------------

    \186\ E.g., Allegheny, Ameren, Arkansas Municipal, Bonneville,
Constellation, CAISO, Entergy, Exelon, FirstEnergy, LPPC,
MidAmerican, Santee Cooper, Seattle, and TAPS.
---------------------------------------------------------------------------

    304. PJM suggests that the data exchange protocols be developed as
minimum requirements and not interfere with existing protocols that PJM
has with neighboring control areas under agreements such as the MISO/
PJM JOA.\187\ Similarly, SPP states that it also has developed seams
coordination agreements with adjoining transmission providers \188\
that fully meet and, in some cases exceed, the Commission's objective
of fostering greater data exchanges between transmission providers.
---------------------------------------------------------------------------

    \187\ Under the PJM/MISO Joint Operating Agreement (JOA) and
other operating agreements modeled on that agreement, parties have
developed comprehensive data exchange protocols to facilitate
coordination and consistent AFC calculations. Much of this data is
supplied through industry standard sources such as NERC SDX and NERC
eTags.
    \188\ SPP has developed seams agreements to exchange ATC data
and coordinate congestion with non-RTO neighbors such as the
Southwest Power Administration. Further, SPP exchanges ATC/AFC data
and coordinates planning, reserve sharing, outage coordination, and
transmission service administration under a transmission
coordination agreement with Associated Electric Cooperative, Inc.
(AECI), an individual transmission provider situated on SPP's border
that is not a member of SPP or any other RTO.
---------------------------------------------------------------------------

    305. MISO is concerned that the NOPR does not address transparency
and regional coordination issues arising at the seams between RTO and
non-RTO regions, particularly with respect to ATC calculations. In
MISO's view, the Commission-approved joint operating agreements between
various ISOs and RTOs contain cutting edge ATC calculation
methodologies, while no comparable common protocols have evolved with
non-RTO utilities. In its reply comments, Exelon agrees with MISO that
the various joint operating agreements are not consistent. Exelon
proposes that the NERC standards specify requirements for coordination
and the type of data that must be exchanged and used for accurate ATC
calculations. Exelon contends that having uniform standards for
coordination developed by NERC will enhance efficiency throughout the
industry, particularly between and among RTO and non-RTO areas.
MidAmerican reiterates that ATC coordination remains an issue for RTOs
and that any improvements in ATC coordination resulting from this
proceeding must apply to the OATTs of RTOs and non-RTOs alike.
    306. NAESB states that coordination and data exchange may require
business practices for existing transmission reservations, including
counterflows, ATC calculation frequency, and source/sink modeling
identification. Some commenters request that the Commission clarify
that only information necessary for purposes of ATC modeling needs to
be exchanged.\189\ In particular, they propose that proprietary
generation or market information data that might harm their competitive
position should not be publicly disseminated since that would not
enhance the ability of transmission providers to accurately calculate
ATC.
---------------------------------------------------------------------------

    \189\ E.g., Allegheny, Constellation, and Indianapolis Power.
---------------------------------------------------------------------------

    307. While acknowledging these confidentiality and commercial
sensitivity concerns, other commenters recommend that the availability
of shared data not be limited to transmission providers.\190\ For
example, TAPS explains that transmission dependent utilities need an
opportunity to access the data periodically as a check on the process.
To address confidentiality or standards of conduct concerns, TAPS
proposes that transmission dependent utilities' access to data could be
achieved through an employee barred from disclosing information to
marketing staff or a third party independent consultant retained by the
transmission dependent utility. However, APPA and Seattle urge the
Commission to eliminate artificial and institutional barriers to the
exchange of data and information.
---------------------------------------------------------------------------

    \190\ E.g., APPA, Bonneville, TAPS, and Seattle.
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    308. APPA and Seattle also contend that, even if data were openly
available, the vast quantities of hourly data points are difficult to
manage, process and analyze using existing methods. To address this
issue, APPA recommends

that the Commission encourage ongoing efforts to obtain greater
resolution of system-model State variables, contractual uses and
probabilistic ranges and to refine data management and analytical
methods.
    309. New York Commission suggests having an overarching entity,
such as a Transmission Oversight Center, that is responsible for
calculating and coordinating ATC between various ISOs/RTOs could
overcome this lack of data.
Commission Determination
    310. The Commission adopts the NOPR proposal and directs public
utilities, working through NERC, to revise the related MOD reliability
standards to require the exchange of data and coordination among
transmission providers and, working through NAESB, to develop
complementary business practices. The following data shall, 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. 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.
    311. While there is a near consensus among commenters that
significant improvements in the communication, coordination, and
exchange of data across all transmission providers are needed to
produce accurate determinations of ATC, we acknowledge the concerns of
ISO/RTOs that new data exchange protocols may interfere with the
existing protocols and seams coordination agreements. Although we will
not provide a blanket exemption for ISOs and RTOs from meeting or
exceeding the data exchange requirements of this Final Rule, they may,
as explained in section IV.C.2, demonstrate in relevant filings that
their existing data exchange protocols are consistent with or superior
to those that are developed in the NERC and NAESB processes.\191\
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    \191\ We are not requiring that every transmission provider
follow identical protocols. Rather, all transmission providers must
meet the relevant NERC reliability standards and NAESB business
practices, and each entity will be subject to reliability standards
compliance audits through which they will have to demonstrate that
they meet or exceed the reliability standards.
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    312. With respect to concerns regarding the exchange of data that
may be a subject of confidentiality and commercially sensitive, we only
require information necessary for purposes of ATC modeling to be
exchanged. As suggested by some commenters, proprietary generation or
market information data that might harm a competitive position should
not be publicly disseminated, since that would not enhance the ability
of transmission providers to accurately calculate ATC. If any of the
data are subject to confidentiality and are commercially sensitive,
they must be disclosed in accordance with a confidentiality agreement.
2. Transparency
a. OATT Transparency
(1) Attachment C
NOPR Proposal
    313. In the NOPR, the Commission proposed to require each
transmission provider to include in Attachment C of its OATT more
descriptive information concerning its ATC/AFC calculation methodology.
Specifically, the Commission proposed to require the transmission
provider to state its specific mathematical algorithm used to calculate
firm and non-firm ATC/AFC for its scheduling horizon, operating
horizon, and planning horizon. The Commission also proposed to require
transmission providers to provide a process flow diagram that
illustrates the various steps through which ATC/AFC is calculated. In
addition, the Commission proposed to require transmission providers to
provide definitions and explain in detail how TTC, ETC, AFC, TRM, and
CBM are calculated for both operating and planning horizons.
Comments
    314. Most commenters support the Commission's overall proposal on
transparency in ATC calculations.\192\ Numerous commenters support the
Commission's proposal to require detailed information in Attachment C
regarding the transmission provider's ATC/AFC calculation
methodology.\193\ Barrick agrees in its reply comments that a thorough
explanation of how ATC is calculated should be made readily available
either in the transmission provider's OATT or on its OASIS, thereby
improving transparency and making it less difficult for customers to
determine whether the calculations are unduly discriminatory. Old
Dominion calls for greater transparency in the details of calculating
ATC, even as applied to RTOs such as PJM because of the relevance of
ATC at the borders of an RTO/ISO and the market impact of
inconsistencies in definitions, data, modeling assumptions and
frequency of ATC calculations. NERC states that the revised NERC
reliability standards will address transparency.
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    \192\ E.g., Alberta Intervenors, AWEA, Bonneville, CAISO,
Constellation, Duke, East Texas Cooperatives, ELCON, Entergy,
Entegra, EPSA, E.ON, Exelon, MidAmerican, Morgan Stanley,
Municipals, Nevada Companies, NPPD, PGP, PJM, Powerex, CREPC, Santee
Cooper, TVA, TAPS, and TDU Systems.
    \193\ E.g., Arkansas Municipal, Arkansas Commission, CAISO,
Constellation, ELCON, Entergy, ISO New England, Morgan Stanley,
NARUC, Nevada Companies, Occidental, PJM, Powerex, Project for
Sustainable FERC Energy Policy, Santee Cooper, and Suez Energy NA.
---------------------------------------------------------------------------

    315. NARUC contends that understanding ATC calculation
methodologies and having access to the underlying data is essential to
a range of critical State commission functions and, therefore, greater
transparency of ATC information will significantly enhance State
commissions' abilities to fulfill their statutory obligations. On
reply, North Carolina Agencies agree with NARUC and state that efforts
aimed at increased transparency of ATC calculations should help uncover
any actual discriminatory behavior by transmission providers, provide a
clearer standard against which to evaluate claims of unduly
discriminatory activities, and facilitate regional planning efforts.
Entegra states on reply that transmission providers should be required
to post narratives explaining changes in models and factors underlying
ATC and AFC values, which would be invaluable to the Commission and
customers in identifying problems that may warrant enforcement actions.
    316. While APPA generally supports the Commission's proposal, some
of APPA's members along with other commenters express concern that
including all the information might be too burdensome and result in
numerous tariff changes.\194\ Some APPA members in the West also
express concerns about the competitive implications of

providing such confidential and sensitive information.
---------------------------------------------------------------------------

    \194\ E.g., EEI, PNM-TNMP, Sacramento, Seattle, and Southern.
---------------------------------------------------------------------------

    317. EEI also notes that providing additional detailed information
in Attachment C would be duplicative and may result in confusion due to
inconsistencies between the wording of the NERC and NAESB ATC documents
and each transmission provider's Attachment C. To avoid uncertainty,
EEI recommends that the Commission require transmission providers to
comply with the requirements of Attachment C by referencing NERC
reliability standards or business practices that provide the
information that is called for in the Attachment. MidAmerican believes
that additional information concerning calculating ATC and its
components would best be retained in the transmission provider's
business practices rather than Attachment C. In its reply comments,
Powerex suggests an alternative of permitting transmission providers to
provide a general reference to NERC, WECC, or NAESB standards and fully
outline core definitions, processes, data and assumptions when
deviating from such standards.
    318. Southern contends that the transparency concerns expressed in
the NOPR are driven more by the complexity and volume of the data
involved rather than a lack of information. Southern suggests that
sufficient information is readily available and the best course of
action by the Commission would be to focus on documenting transfer
capability methodologies available to transmission customers. NRECA
replies that many commenters provided input into why more transparency
is needed and repeats the example provided in its NOI comments of a
cooperative that spent many months in discussions with a public utility
transmission provider in an effort to understand ATC-related
information posted on OASIS.
    319. Pinnacle contends that the Commission's proposal for detailed
information in Attachment C is only relevant in flow-based systems,
pointing out that in the Western Interconnection, the scheduling
horizon, and the operating horizon are the same and thus reporting such
information is not necessary. APPA and Bonneville believe that adding
such detail in Attachment C may only result in incremental changes and
suggest that better regional coordination would provide greater
transparency.
    320. Though ISO New England believes this proposal would not create
an undue burden, it urges the Commission to allow for variety in the
illustration of the process flow diagram. Regarding the proposal to
require a ``detailed explanation'' of the calculation of ATC, TTC, ETC,
and TRM components, ISO New England argues that the relevant inputs can
change on a daily basis because ATC for Pooled Transmission Facilities
(PTF) in New England is a function of market conditions, as opposed to
an administratively-derived calculation. In ISO New England's view, the
level of detail required should reflect the operation of competitive
markets. MISO is concerned that the NOPR does not address transparency
and regional coordination issues arising at the seams between market
and non-market areas, particularly with respect to ATC calculations.
    321. MidAmerican strongly urges the Commission to ensure that non-
public utility transmission providers adhere to the transparency
requirements, since in the Pacific Northwest many of the ``backbone''
transmission lines are co-owned by jurisdictional and nonjurisdictional
entities. A jurisdictional co-owner may be limited in its ability to
determine such parameters as TRM and CBM because it may not be the line
operator. LPPC, in its reply comments, believes it is unnecessary and
redundant to require non-public utility transmission providers to adopt
the ATC requirements of the pro forma OATT, because the Commission
recognizes in the NOPR that NERC and NAESB are currently drafting
standards for ATC, which when final will be filed with the Commission
and become part of the ERO's mandatory reliability standards and fully
applicable to otherwise nonjurisdictional entities.
    322. Suez Energy NA contends that it is essential that the
Commission include an explanation of each component of the ATC
calculation in Attachment C to ensure that the transmission provider
incorporates NERC standards appropriately and to ensure proper
enforcement in the event that an audit shows that the transmission
provider has employed other methods of calculating ATC. Suez Energy NA
also notes that the mathematical algorithms and process flow diagrams
should be provided to users of the transmission system, independent
monitors, transmission coordinators and regulators, even if a
confidentiality agreement is required. APPA suggests that the
Commission and regional reliability organizations conduct additional
audits to ensure that these posted practices and procedures are in fact
being followed, and that the data used are verifiable.
Commission Determination
    323. The Commission adopts the NOPR proposal to increase
transparency regarding ATC calculations by requiring each transmission
provider to set forth its ATC calculation methodology in its OATT. Each
transmission provider must, at a minimum, include the following
information in Attachment C to its OATT. It must clearly identify which
of the NERC-approved methodologies it employs (e.g., contract path,
network ATC, or network AFC). It also must provide a detailed
description of the specific mathematical algorithm the transmission
provider uses to calculate firm and non-firm ATC for the scheduling
horizon (same day and real-time), operating horizon (day ahead and pre-
schedule), and planning horizon (beyond the operating horizon). In
addition, transmission providers must include a process flow diagram
that describes the various steps that it takes in performing the ATC
calculation. Furthermore, transmission providers must set forth a
definition of each ATC component (i.e., TTC, ETC, TRM, and CBM) and a
detailed explanation of how each one is derived in both the operating
and planning horizons. Requiring transmission providers to file a
statement of their ATC calculation methodology along with a process
flow diagram and more detailed definitions of ATC components in
Attachment C of the OATT will provide greater transparency to
transmission customers and assist in identifying any discrepancies that
may arise in ATC determinations. These new requirements will assist in
alleviating any appearance of discrimination in the determination of
ATC.
    324. The Commission acknowledges NARUC's comments that
understanding ATC methodologies and the underlying data also will
enhance State regulators' ability to meet their regulatory obligations.
More transparent ATC calculations are critical to coordinated regional
transmission planning that ultimately will improve transmission access
for customers and enhance grid reliability. Transparent ATC
calculations facilitate the ability of market participants and
regulators to detect discrimination.
    325. We do not believe our requirement to include additional
information in Attachment C will be overly burdensome or lead to an
excessive level of future tariff revisions. Attachment C must provide
an accurate documentation of processes and procedures related to the
calculation of ATC, not the actual mathematical algorithms themselves,
which should be

posted on the transmission provider's Web site. These processes define
service availability and, as such, must be part of the transmission
provider's OATT. It is entirely appropriate that, because revisions to
such processes impact transmission availability, they should be filed
for Commission approval and included in a transmission provider's OATT.
We also require transmission providers to file a revised Attachment C
to incorporate any changes in NERC's and NAESB's revised reliability
standards and business practices related to ATC calculations, as
requested by the Commission in this Final Rule. This filing should be
made within 60 days of completion of the NERC and NAESB processes. As
we expect transmission providers to rarely change their ATC calculation
methodologies, we do not believe this requirement will trigger an
unacceptable level of tariff filings modifying the Attachment C
description of the ATC components and processes.
    326. We agree with ISO New England that the process flow diagram
requirement may be met with a variety of illustrations, so long as it
is of sufficient detail to provide the transmission customer with a
reasonable understanding of the transmission provider's ATC calculation
processes. The process flow diagram should support the other Attachment
C requirements. As noted above, we agree with Suez Energy NA that
mathematical algorithms and process flow diagrams should be made
available. We do not find that a confidentiality agreement is
generically warranted; however, we note that, a transmission provider
may require a confidentiality agreement for CEII materials, consistent
with our CEII requirements, or may otherwise protect the
confidentiality of proprietary customer information.
    327. We also require transmission providers to document their
processes for coordinating ATC calculations with their neighboring
systems. This requirement is particularly important with respect to
seams between market and non-market areas, as identified by MISO, and
with respect to the request of other commenters to increase regional
coordination regarding ATC calculation. While this Final Rule does not
address all seams issues between market and non-market areas, it does
take important steps towards that end by improving data exchange
between transmission providers and providing increased transparency
with respect to ATC calculation.
    328. We reject proposals to address the transparency of ATC
methodology by merely referencing business practices and reliability
standards developed by NERC, NAESB, and WECC.\195\ ATC calculations
have a direct and tangible effect on the granting of open access
transmission service.\196\ As such, an accurate and detailed statement
of the methodology and its components that defines how the transmission
provider determines ATC belongs in the transmission provider's OATT as
the means of holding the transmission provider accountable for
following non-discriminatory procedures for granting service, not in
business practices kept by the transmission provider.\197\ However, as
noted above, the actual mathematical algorithms should be posted on the
transmission provider's web site, with the link noted in the
transmission provider's Attachment C.
---------------------------------------------------------------------------

    \195\ WECC has on file a Reliability Management System agreement
under which transmission providers agreed, through contracts, to
follow WSCC reliability criteria. Western Systems Coordinating
Council, 87 FERC ] 61,060 (1999).
    \196\ The Commission recognized in Order No. 889 that the
methodology for calculating ATC and TTC belongs in the tariff. Order
No. 889 at 31,607. At the time, the industry represented that it was
engaged in efforts to develop uniform methods of determining ATC.
The Commission encouraged such industry efforts and required that
the tariff include the methodology, which was to be based on current
industry practices, standards and criteria.
    \197\ For the same reason, the Commission disagrees with the
assertions of Southern and EEI that more information in Attachment C
would be duplicative because some ATC-related information is already
available elsewhere.
---------------------------------------------------------------------------

    329. We also reject Pinnacle's assertion that more detailed
information in Attachment C would only apply to flow-based systems.
Regardless of what type of ATC calculation methodology is employed,
transparency in ATC calculations is critical to avoid undue
discrimination when allocating transmission capacity under the pro
forma OATT.
    330. In response to MidAmerican's comments regarding the
applicability of the ATC-related reforms to non-public utilities, we
again refer to section IV.C.3 where we discuss this issue generally. We
note here, however, that the ERO's reliability standards currently in
development before the Commission will be applicable to all users,
owners and operators of the bulk electric grid, which includes non-
public utilities.
    331. We do not believe ATC-specific tariff audits are necessary to
order at this time. The Commission will continue to provide oversight
of all tariff-related activities through its enforcement program.
Moreover, ATC requirements will be part of the mandatory and
enforceable reliability standards and, as such, will be subject to
compliance audits through that process.
(2) CBM Practices
NOPR Proposal
    332. In the CBM Order, the Commission required transmission
providers to post a specific narrative explanation of their CBM
practices.\198\ In addition, the Commission directed transmission
providers to post their procedures for allowing access to CBM during
emergencies. The Commission further stated in the CBM Order that, if a
utility's practice was not to set aside transfer capability as CBM, it
should reflect that in Attachment C.
---------------------------------------------------------------------------

    \198\ Capacity Benefit Margin in Computing Available
Transmission Capacity, 88 FERC ] 61,099 (1999) (CBM Order).
---------------------------------------------------------------------------

    333. In the NOPR, the Commission proposed to require transmission
providers to include this CBM narrative in Attachment C of their OATTs.
In addition, the Commission proposed that transmission providers
explain their definition of CBM, list the databases used in their CBM
calculations, and prove that there is no double-counting of contingency
outages when performing CBM calculations.
Comments
    334. Seattle and Suez Energy NA support this proposal. Seattle
states that CBM information should be specified in Attachment C in
order to provide clear guidance for the specific information that is
posted on OASIS. Seattle and APPA suggest that CBM should be verifiable
and subject to audit by independent parties such as regional
reliability organizations.
    335. EEI suggests that the Commission revise Attachment C, section
3(f) to replace the word ``prove'' with the word ``demonstrate'' in the
requirement that the transmission provider ``prove'' that it does not
double count contingency outages when calculating CBM, TTC and TRM. EEI
notes that the term ``prove'' implies a determination on the merits
after evaluation of competing arguments and evidence. A transmission
provider should be able to satisfy its obligations by ``demonstrating''
the absence of a double count. Any customer that wishes to challenge
the demonstration can do so, at which time the issue of ``proof'' would
arise.
    336. With regards to ``double counting,'' TVA references TRM and
agrees that additional explanations regarding the calculation of TRM,
including methods used to avoid double counting contingency events,
should improve transparency in providing open access transmission
service. TVA points out that this is being addressed by a NERC
standards drafting team.

Commission Determination
    337. The Commission adopts the NOPR proposal requiring additional
information in the transmission provider's OATT Attachment C regarding
its determination of CBM. Transmission providers must provide in
Attachment C a narrative description detailing their CBM practices. In
addition, a transmission provider must explain its definition of CBM
and list the databases used to derive its value. These new requirements
will provide transmission customers transparency into the CBM component
of ATC and help discourage the potential for undue discrimination in
the calculation and use of CBM.
    338. We adopt EEI's proposal that the Commission revise Attachment
C, section 3(f) to replace the word ``prove'' with the word
``demonstrate.'' The word ``demonstrate'' more accurately describes the
showing we expect the transmission provider to make. We agree that the
word ``prove'' implies a standard of proof that we did not intend to
impose. We also acknowledge TVA's comments that the NERC standards
drafting team is developing standards that should address ``double
counting'' in ATC calculations in general. However, we require that the
information in Attachment C be sufficient to demonstrate that a
transmission provider is not double counting CBM in its ATC
calculation.
    339. Finally, the Commission rejects the proposal by Suez Energy
NA, APPA, and Seattle to establish formal audits of CBM set asides.
Requirements for CBM will be part of the mandatory and enforceable
reliability standards and, as such, will be subject to compliance
audits through that process. Moreover, the Commission provides
oversight of all tariff-related activities through its enforcement
program.
b. OASIS
(1) ATC/TTC Posting Requirements
NOPR Proposal
    340. The Commission's existing regulations require certain ATC-
related information to be posted on each transmission provider's OASIS
and other information to be provided on request. To ensure that
relevant information is available on a timely basis to all market
participants, the Commission proposed in the NOPR to amend its
regulations to allow potential customers greater access to information
that will enable them to obtain service on a non-discriminatory basis
from any transmission provider.
    341. The Commission noted in the NOPR that existing regulations
require ATC and TTC calculations to be performed according to
consistently applied methodologies referenced in the transmission
provider's OATT and current industry practices, standards and criteria.
The Commission proposed that these calculations be based on the ERO
reliability standards.
    342. The Commission further proposed to maintain the requirement
that transmission providers provide, on request, all data used to
calculate ATC and TTC for any constrained paths. Transmission providers
also would remain required, on request, to make publicly available any
system planning studies or specific network impact studies performed
for customers and to post a list of such studies on OASIS.
Comments
    343. Several commenters support the proposal to post ATC-related
information on OASIS.\199\ TDU Systems supports each of the
Commission's proposals with respect to providing easier access to data
underlying ATC calculations and greater transparency to the process.
Sacramento states that posting on OASIS will ensure proper public
access, but will avoid the need for Commission approval of an OATT
change.
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    \199\ E.g., APPA, Constellation, FirstEnergy, Indianapolis
Power, Sacramento, Suez Energy NA, TAPS, and TDU Systems.
---------------------------------------------------------------------------

    344. Constellation strongly supports the need for additional
transparency, stating that providing transmission customers with
meaningful insight into the current ``black box'' determination of ATC
will help minimize the mystery underlying many transmission provider
responses to service requests. According to Constellation, further
transparency will assist customers in predicting the outcome of
transmission service requests and facilitate increased commercial
activity. Constellation suggests that the Commission require
transmission providers to provide transmission customers, on request,
with specific details related to modeling data, modeling support
information, modeling benchmarking and forecasting data, and
transmission service request audit data. It requests that the
information be in a form and format usable by the transmission
customers and that the Commission take steps to ensure that
transmission customers understand how ATC is calculated and the data
inputs are used to affect those calculations.
    345. Great Northern likewise requests that the Commission enhance
the requirement to provide all data on request, specifically on
constrained paths, by requiring a posted tabulation of annual and
monthly ATC calculation details. Great Northern suggests including TTC,
network load for each transmission customer, capacity reserved for each
network resource, each point-to-point transmission service reservation,
CBM and other deductions from TTC.
    346. APPA members support the posting of ATC information, as it
will assist in using ATC more efficiently, and they support the posting
of system planning studies and specific network impact studies that the
transmission provider performs for its own merchant function, as well
as studies performed for customers. In addition, APPA suggests the
posting of facilities studies at the time they become available,
assuming that this can be done consistent with CEII concerns. TAPS goes
further by urging the Commission to close gaps in the current OASIS
requirements by requiring posting of all studies performed for
transmission owners' own transmission network resource designations and
other uses of the system, including facilities studies as well as
system impact studies, ensuring posted study lists are updated
contemporaneously with the availability of new studies, and requiring
retention of studies for a minimum of five years.
    347. Nevada Companies and TVA support cost effective measures that
increase transparency in transmission operations and, unless the
requirement becomes unduly time consuming or burdensome, in general
support more disclosure rather than less.
Commission Determination
    348. The Commission adopts the proposal in the NOPR to continue to
require transmission providers to comply with existing ATC-related
posting obligations as supplemented by this Final Rule. The Commission
will continue to require transmission providers, on request, to make
available all data used to calculate ATC and TTC for any constrained
paths and any system planning studies or specific network impact
studies performed for customers. Transmission providers must also
continue to post a list of such studies on OASIS.
    349. In addition, we agree with the requests of APPA and TAPS to
require the additional posting of, at a minimum, a listing of all
system impact studies, facilities studies, and studies performed for
the transmission provider's own network resources and affiliated
transmission customers, to be made available upon request. We note that
appropriate procedures to accommodate CEII concerns should be developed
to

ensure eligible entities with a legitimate interest in transmission
study data can receive access to it. Also, we adopt TAPS' suggestion
that the studies be made available for five years to make the
requirement consistent with data retention requirements pertaining to
denial of service requests.
    350. The Commission rejects Constellation's and Great Northern's
proposals to require transmission providers to provide upon request or
regularly post additional information beyond that required in the
regulations and this Final Rule. The transmission provider is already
required to make available, upon request and in electronic format, all
information related to the calculation of ATC and TTC for any
constrained path. Accordingly, we see little benefit to require
transmission providers to provide upon request or regularly post
additional information suggested by these commenters.
(2) CBM/TRM Posting Requirements
NOPR Proposal
    351. The Commission's OASIS regulations currently require
transmission providers to calculate and post ATC and TTC for each
posted path, but make no requirement for CBM and TRM postings. In the
CBM Order, however, the Commission required transmission providers,
with respect to each path for which the utility already posts ATC, to
post (and update) the CBM figure for that path. The Commission also
required transmission providers to make any transfer capability set
aside for CBM available on a non-firm basis and to post this
availability on OASIS. In the NOPR, the Commission proposed to
incorporate these CBM posting requirements into its regulations. The
Commission also proposed that transmission providers post (and update)
the TRM values for the paths on which the transmission provider already
posts ATC, TTC, and CBM.
Comments
    352. Several commenters strongly support the Commission's proposal
to require transmission providers to post TRM and CBM.\200\ APPA and
EPSA agree that the posting of TRM for near term transmission services
would provide greater assurance that ATC calculations are being
performed according to established procedures. Since transmission
providers already have this information, FirstEnergy states that it
does not appear to be unduly burdensome for them to post such
information. Bonneville indicates that it currently posts TRM values in
its Business Practices Forum, which is useful for examining curtailment
events, supporting transmission planning objectives, and validating
posted ATC values.
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    \200\ E.g., Powerex, PJM, PPL, Seattle, and Pinnacle.
---------------------------------------------------------------------------

    353. EPSA also recommends that the Commission provide guidance on
standards that should be developed to require each transmission
provider to notify the Commission in writing and post a notice on its
OASIS within 24 hours of a transmission provider's use of CBM to import
emergency power. EPSA also requests that the amount of CBM reserved for
each interface be posted on OASIS.
Commission Determination
    354. The Commission adopts the CBM posting requirements proposed in
the NOPR. In doing so, we amend our OASIS regulations to incorporate
the directives established in the CBM Order. Accordingly, we require
transmission providers to post (and update) the CBM amount for each
path. In addition, the Commission requires transmission providers to
make any transfer capability set aside for CBM but unused for such
purpose available on a non-firm basis and to post this availability on
OASIS. Furthermore, the Commission requires transmission providers to
post (and update) the TRM values for the paths on which the
transmission provider already posts ATC, TTC, and CBM.
    355. We reject EPSA's request to require transmission providers to
notify the Commission in writing and post a notice on OASIS within 24
hours of a transmission provider's use of CBM to import emergency power
and transfer capability set aside as CBM at each of the transmission
provider's interfaces. The additional transparency of CBM-related
information provided in this Final Rule, along with the reforms related
to consistency of CBM, will cause sufficient information to be made
available to customers concerning the use of CBM. The use and
allocation of CBM and TRM will be more transparent to transmission
customers, thus reducing the potential for undue discrimination.
(3) Periodic Reevaluation of the CBM Set-Aside
NOPR Proposal
    356. In the CBM Order, the Commission stated that the level of ATC
set aside for CBM can and should be reevaluated periodically to take
into account more certain information (such as assumptions that may not
have, in fact, materialized).\201\ The Commission therefore directed
transmission providers to periodically reevaluate their generation
reliability needs so as to make known the availability of CBM and to
post on OASIS their practices in this regard.\202\ In the NOPR, the
Commission proposed to incorporate these requirements in the
Commission's regulations and to obligate transmission providers to
reevaluate the CBM set-aside at least quarterly.
---------------------------------------------------------------------------

    \201\ CBM Order at 61,237.
    \202\ Id.
---------------------------------------------------------------------------

Comments
    357. Some commenters support quarterly reevaluation of CBM set-
asides.\203\ TAPS agrees with the need for full transparency of CBM
reservations and practices and states that, because CBM values may
differ from season to season, CBM values should be separately
calculated for at least each quarter. However, TAPS does not find that
it is necessary or appropriate for the CBM values to be reevaluated
quarterly, given the effort involved in collecting the data and
performing the modeling analysis. Rather, CBM studies should be
performed at least every other year, supplemented with ``off-year
studies'' when appropriate.
---------------------------------------------------------------------------

    \203\ E.g., EPSA, Sacremento, Santa Clara, Suez Energy NA, and
TDU Systems.
---------------------------------------------------------------------------

Commission Determination
    358. The Commission incorporates into its regulations the
requirement in the CBM Order for a transmission provider to
periodically reevaluate its transfer capability set-aside for CBM. With
respect to TAPS' concerns over the effort involved in the re-evaluation
process, we will require CBM studies to be performed at least every
year. This requirement is consistent with the CBM Order, in which the
Commission stated that the level of ATC set aside for CBM should be
reevaluated periodically to take into account more certain information
(such as assumptions that may not have, in fact, materialized).\204\
While changes requiring a reevaluation of CBM are longer-term in nature
(e.g., installation of a new generator or a long-term outage),
quarterly may be too frequent, though two years may be too long and may
prevent a portion of the CBM set-aside from being released as ATC.
Moreover, annual reevaluation is consistent with the current NERC
standard being developed in MOD-005.\205\ The requirement to evaluate
CBM at least every year also is consistent with the CBM Order in that

the Commission directed transmission providers to periodically
reevaluate their generation reliability needs so as to make known the
need for CBM and to post on OASIS their practices in this regard.
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    \204\ CBM Order at 61,237.
    \205\ The MOD-005 reliability standard establishes the procedure
for verifying CBM values.
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(4) ATC/TTC Narrative Explanation
NOPR Proposal
    359. In the NOPR, the Commission proposed to largely retain
existing posting requirements for unconstrained posted paths, but to
amend the regulations relating to data posted for constrained posted
paths. Existing regulations require ATC and TTC on constrained paths to
be updated when (1) Transactions are reserved, (2) service ends, or (3)
whenever the TTC estimate for the path changes by more than 10
percent.\206\ In the NOPR, the Commission proposed to supplement the
existing regulations by requiring the transmission provider to post a
brief, but specific, narrative explanation of the reason for the change
at the time a change in monthly and yearly ATC values on a constrained
path is posted. The Commission sought comment on whether the posting of
this new information would provide adequate transparency to the
customer on a frequent enough basis without imposing an undue burden on
the transmission provider. The Commission also sought comment on
whether a similar narrative should be required when ATC remains
unchanged at a value of zero for some specified period of time.
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    \206\ See 18 CFR 37.6(b)(3)(i)(C).
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Comments
    360. Some commenters support the Commission's proposal to require
transmission providers to post more detailed explanations about changes
in ATC values on their OASIS sites.\207\ NAESB, TranServ, and Williams
request that the Commission clarify the regulatory requirements for
posting of updated ATC values such as the level of standardization,
frequency and time of postings, and other requirements. CAISO believes
that ATC should be updated on a daily basis.
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    \207\ E.g., Arkansas Commission, CAISO, Constellation, East
Texas Cooperatives, Exelon, FirstEnergy, LPPC, Morgan Stanley,
NRECA, Pinnacle, Powerex, Santa Clara, and Suez Energy NA.
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    361. Powerex and Nevada Companies propose that additional
disclosures be posted, such as data on grandfathered contracts, time-
specific data relevant to transmission constraints and ATC rights on
posted paths, and remaining customer rights under a reservation-based
network service system.
    362. A few commenters caution that some of the data that the
Commission is requiring to be posted by transmission providers is
market-sensitive and, if posted on a real-time basis, could be used by
third parties to obtain an unfair competitive advantage.\208\ These
commenters propose that the transmission providers should be allowed a
brief period of delay (e.g., one week) before posting data.
Indianapolis Power also advocates a delay due to the burden on
transmission providers of the new posting.
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    \208\ E.g., Ameren, ISO New England, Southern, and NRECA.
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    363. Several commenters oppose the Commission's proposal to require
that transmission providers post narratives on OASIS outlining reasons
why monthly and yearly ATC values on constrained paths change.\209\
These commenters contend that this will cause undue burden on
transmission providers without providing customers with any significant
or new information. They also argue that the proposal is impractical
and will not result in providing transmission customers with meaningful
information regarding transmission service options.
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    \209\ E.g., Ameren, EEI, Entergy, MISO, Pinnacle, PJM, PNM-TNMP,
Southern, TranServ, and TVA.
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    364. If such a requirement is adopted, MISO recommends that a
threshold higher than a 10 percent change in ATC be established and
that the Commission clarify what the term ``specific explanation''
means in this context. PJM states that it already exceeds the
Commission's proposed requirement. However, if strictly applied, this
proposal would be unduly burdensome on PJM because it would require PJM
to post a narrative each hour. PJM asks that the Commission not apply
unnecessary and costly posting requirements on independent RTOs and
ISOs.
    365. EEI and Southern are concerned that monthly ATC may change in
response to every reservation of hourly transmission service because a
reservation of hourly firm service on a constrained path may reduce the
availability of monthly firm service. EEI contends that, if
transmission providers are required to post changes in TTC instead of
ATC, they would not be required to post a new narrative every time a
reservation is made, thus reducing the overall burden on transmission
providers. EEI additionally states that the reasons for changes in TTC
and ATC values often are complex and involve the interaction of
multiple variables in the model that produces the TTC and ATC values
and a specific change in TTC or ATC cannot easily be traced to a
specific change in the inputs. Alternatively, EEI suggests that
transmission providers could post the major changes in the inputs to
the TTC modeling software that are made in connection with each updated
TTC posting without ascribing specific inputs to specific changes in
TTC and ATC values on specific lines.
    366. Several commenters are supportive of the proposed requirement
that transmission providers provide a narrative explanation when ATC
values remain at zero.\210\ APPA suggests that if a particular
interface shows an ATC of zero for a specified period, the transmission
provider should provide a narrative explanation of why this is the case
and how its plans to address this problem. It also suggests that this
information should be employed in the transmission planning process.
East Texas Cooperatives, in reply comments, state that the narrative
can provide useful information to the transmission customers and State
and Federal regulators regarding specific conditions regarding ATC
coordination.
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    \210\ E.g., APPA, East Texas Cooperatives, Suez Energy NA, and
TAPS.
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    367. In supplemental comments, NAESB states that the Commission
should specify whether it is sufficient for the explanation of changes
in ATC or TTC values to be limited to broad generalized statements or
whether the posted information should include such information as the
specific events which gave rise to the change, the new values for ATC
at all points on the network, the impact of the change on transmission
customers, and a detailed snapshot of the conditions on the system at
all flowgates or constrained elements when the change occurred.\211\
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    \211\ November 2, 2006, Addendum to the Testimony of Ronald M.
Mucci on behalf of the North American Energy Standards Board,
Preventing Undue Discrimination and Preference in Transmission
Service, Docket Nos. RM05-25-000 and RM05-17-000, October 12
Technical Conference, pp. 2-3.
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    368. Southern states that posting a narrative when ATC remains at
zero is unwarranted and unnecessary, as it simply indicates that the
market has responded to market signals of ATC availability and
purchased all available capacity.
Commission Determination
    369. The Commission adopts the NOPR proposal, with the
modifications discussed below, to require that the transmission
provider post a brief, but specific, narrative explanation of the
reason for a change in monthly and yearly ATC values on a constrained
path. Rather than requiring a narrative

when a monthly or yearly ATC value changes as a result of transactions
being reserved, service ending, or the TTC estimate for the path
changing by more than 10 percent, we will require a narrative when a
monthly or yearly ATC value changes only as a result of a 10 percent
change in TTC. This will reduce the number of ATC changes for which a
narrative will be required and address concerns that the new
requirement unduly burdens transmission providers. Any remaining burden
is justified by the benefit to transmission customers of receiving
timely information regarding changes in TTC that result in changes to
ATC. In addition, we adopt NAESB's suggestion that posted information
include the (1) Specific events which gave rise to the change and (2)
new values for ATC on that path (as opposed to all points on the
network).
    370. We reject calls for delays prior to posting data. While
commenters allege the possibility of granting others a competitive
advantage through the release of ``market-sensitive'' data, they have
proffered no evidence to support the allegation of potential harm.
    371. We do require, as suggested in the NOPR, a narrative with
regard to monthly or yearly ATC values when ATC remains unchanged at a
value of zero for a significant period, and will set that period at six
months or longer. This information will be valuable to customers and
regulators in assessing the ability of a transmission provider's
facilities to meet existing service requests. The information also will
provide assurance to customers that the transmission provider is
diligent in regularly evaluating ATC on all paths, monitoring
persistent constraints and addressing them in its planning processes.
    372. Finally, we reject CAISO's suggestion that ATC be updated
daily on a transmission provider's OASIS site, because CAISO offered no
justification for the proposal.
(5) Denial of Service/Records Retention
NOPR Proposal
    373. In the NOPR, the Commission proposed to maintain the
requirement that a transmission provider post the reason for a denial
of a request for service. The Commission also proposed to amend this
provision to require a transmission provider to maintain and make
available information supporting the reason for the denial. The
Commission further proposed to extend the time period for which
transmission providers must maintain transmission service information
for audit. Currently, regulations require that audit data be retained
and made available upon request for download for three years from the
date when they are first posted. The Commission proposed to change the
period from three to five years.
Comments
    374. Many commenters support posting of the reasons for denying
service and the 5-year retention proposal.\212\ TAPS supports the
proposal but suggests several modifications. First, it suggests that
the Commission clarify the requirement to post the reasons for denying
service is triggered not only by denial of the entirety of a
transmission request, but to any disposition that falls short of a full
unconditional grant of the service (with rollover rights if
applicable). Second, TAPS recommends that the regulatory text of
proposed section 37.6(e)(2)(ii) be modified to make the supporting data
available, upon request, to any eligible customer rather than just to
the customers who were denied service. Third, it asks that the
Commission expand its OASIS regulations to require the transmission
provider to maintain and make available on request the information
supporting the disposition (positive, negative, or in between) of its
own network resource designations and other usage needs. East Texas
Cooperatives suggest that the Commission also require that transmission
providers distinguish between denials of requests for firm and non-firm
transmission service.
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    \212\ E.g., APPA, Arkansas Commission, Arkansas Municipal, Duke,
East Texas Cooperatives, MISO, ISO New England, Williams, Nevada
Companies, PPL, Sacremento, Sant Clara, Suez Energy NA, and TDU
Systems.
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    375. Some commenters urge the Commission to clearly define the
scope of any transmission service request information subject to the
proposed five-year record retention requirement to ensure that no undue
administrative burden is placed on transmission providers.\213\ TVA
questions the need to extend the time period for an additional two
years. TVA states that the benefits of extension are not commensurate
with the increased costs, since it is unaware of any problems that have
arisen with the current three-year timeline. Seattle argues on reply
that the Commission should retain the NOPR posting requirements in the
Final Rule because information on actual transmission congestion can be
helpful instead of sole reliance on simulation models.
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    \213\ E.g., MidAmerican, PacifiCorp, PNM-TNMP, and PJM.
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Commission Determination
    376. As proposed in the NOPR, the Commission maintains the
requirement that a transmission provider post the reason for a denial
of service and extends from three years to five years the period for
which transmission providers must maintain data providing reasons for
denial of service. In general, commenters support the requirement for
posting denial of service information and the increase in retention
time to five years, indicating that such information can be helpful to
customers in their awareness of actual transmission congestion, rather
than relying on simulation models.