unregulated transmitting utility to provide transmission services'' at
rates that are comparable to those it charges itself and under terms
and conditions (unrelated to rates) that are comparable to those it
applies to itself and that are not unduly discriminatory or
preferential. The language does not limit the Commission to ordering
transmission services only to the public utility from whom the non-
public utility takes transmission services, but rather it can
reasonably be read to permit the Commission to order the non-public
utility to provide ``open access'' transmission service, i.e., service
to all eligible customers.
    105. In the NOI, we sought comment on whether the Commission should
exercise the authority granted to it by Congress in FPA section 211A.
If so, we asked whether the Commission should impose this requirement
on all unregulated transmitting utilities through a rulemaking
proceeding, or whether the Commission should instead apply this new law
on a case-by-case basis, through complaints, motions seeking
enforcement, or sua sponte action by the Commission.
Comments
    106. Several non-public utility commenters suggest that the
Commission should not use the authority granted by FPA section 211A in
a generic fashion.\102\ They argue that there is no need to require
unregulated transmitting utilities either to file open access tariffs
with the Commission or to require that they adhere to a pro forma OATT.
APPA asserts that while the Commission may act under FPA section 211A
to remedy particular issues that are brought to its attention with
respect to lack of access, there is simply no basis for concluding that
there currently exists a general problem regarding the provision of
transmission service by non-public utility transmission providers which
calls for a generic solution. LPPC proposes a regime of voluntary
compliance with a set of proposed comparability guidelines.
---------------------------------------------------------------------------

    \102\ E.g., Chelan, Douglas, LDWP, LPPC, Northwest Unregulated
TUs, Public Power Council, Rural Utilities Service, Sacramento,
Santee Cooper, Snohomish, Tacoma, TAPS, and TVA.
---------------------------------------------------------------------------

    107. Many commenters argue that the Commission should exercise its
authority granted by FPA section 211A by establishing a rule to require
unregulated transmitting utilities to provide service under the pro
forma OATT.\103\ EEI believes a rulemaking is essential to ensure that
all utilities required to provide open access under FPA section 211A do
so and that the Commission should, at a minimum, require unregulated
transmitting utilities to file and provide service under the pro forma
OATT. EPSA and Sempra Global suggest an approach that would not require
an unregulated transmitting utility to file an OATT with the Commission
until it receives a request for service.
---------------------------------------------------------------------------

    \103\ E.g., Ameren, California Commission, Calpine, Cinergy,
EEI, First Energy, Memphis Light, Nevada Companies, Northwest IPPs,
PNM-TNMP, PPL, Progress Energy, and Suez Energy NA.
---------------------------------------------------------------------------

    108. EEI argues that the Commission should use FPA section 211A to
require unregulated transmitting utilities to provide all services they
are capable of providing, not just those that they provide to
themselves. In contrast, APPA states that FPA section 211A establishes
a ``comparability'' standard applicable to non-public utility
transmission owner rates, and a ``comparable and not unduly
discriminatory or preferential'' standard for terms and conditions.
APPA further states that FPA section 211A requires that unregulated
transmitting utilities provide transmission service to others at

rates, terms and conditions ``comparable to those under which the
unregulated transmitting utility provides transmission services to
itself,'' rather than transmission services that they are ``reasonably
capable of providing.''
    109. The Canadian Electricity Association believes that the
adoption of FPA section 211A requires the Commission to revisit the
reciprocity requirement of Order No. 888. According to the Canadian
Electricity Association, EPAct 2005 lowered the bar for domestic
unregulated transmitting utilities, requiring them only to provide
service under terms and conditions that are comparable to those they
apply to themselves, rather than terms and conditions that
substantially conform or are superior to those in the pro forma OATT.
If the Commission does not make corresponding changes to the manner in
which the reciprocity requirement currently applies to Canadian
entities, it argues, the result will be domestic unregulated
transmitting utilities being treated better than Canadian entities,
which would violate the national treatment obligations under the North
American Free Trade Agreement. The Canadian Electricity Association
argues that the reciprocity requirement under Order No. 888 must be
modified to require that a Canadian entity that seeks open access in
the U.S. must provide access to its own transmission system under terms
and conditions that are comparable to those the Canadian entity is
subject to itself.
Discussion
    110. The Commission proposes to retain the current reciprocity
language in the pro forma OATT, as well as Order No. 888's three
alternative provisions for satisfying the reciprocity condition, which
are described above: a non-public utility that owns, controls, or
operates transmission and seeks transmission service from a public
utility must either satisfy its reciprocity obligation under a
bilateral agreement, seek a waiver of the OATT reciprocity condition
from the public utility, or file a safe harbor tariff with the
Commission.\104\
---------------------------------------------------------------------------

    \104\ For non-public utilities that choose to use the safe
harbor tariff, we note that its provisions must be substantially
conforming or superior to the new pro forma OATT. A non-public
utility that already has a safe harbor tariff may amend its tariff
so that its provisions substantially conform or are superior to the
new pro forma OATT if it wishes to continue to qualify for safe
harbor treatment. As the Commission stated in Order No. 888-A, a
non-public utility may limit the use of its voluntarily offered safe
harbor reciprocity tariff only to those transmission providers from
whom the non-public utility obtains open access service, as long as
the tariff otherwise substantially conforms to the pro forma OATT.
See Order No. 888-A at 30,289.
---------------------------------------------------------------------------

    111. We do not propose a generic rule to implement the new FPA
section 211A.\105\ Rather, we will apply its provisions on a case-by-
case basis, such as when a public utility seeks service from an
unregulated transmitting utility that has not requested service under
the public utility's OATT and the reciprocity obligation therefore does
not apply.\106\ A customer may file an application with the Commission
seeking an order compelling the unregulated transmitting utility to
provide transmission service that meets the standards of FPA section
211A. Further, as we indicate below, we expect unregulated transmission
providers to participate in the open and transparent regional planning
processes that we propose to order and note that, if there are
complaints about such participation, we will address them on a case-by-
case basis.
---------------------------------------------------------------------------

    \105\ We note that LPPC has committed to voluntary compliance
with a set of guidelines for the provision of comparable service
under FPA section 211A.
    \106\ We do, however, propose to amend our regulations to make
clear that an applicant in a FPA section 211A proceeding against a
non-public utility that has submitted an acceptable safe harbor
tariff shall have the burden of proof to show why service under the
safe harbor tariff is not sufficient and why a FPA section 211A
order should be granted. See revised 18 CFR 35.28(e)(1)(ii).
---------------------------------------------------------------------------

    112. We disagree with the position of the Canadian Electricity
Association. EPAct 2005 did not repeal the reciprocity obligation in
Order No. 888. Rather, it granted a new avenue of authority to the
Commission to order comparable transmission service from non-public
utilities. We are proposing not to exercise this new authority at this
time. Rather, we are proposing to retain our reciprocity policy, which
was adopted pursuant to sections 205 and 206 of the FPA. By maintaining
the same reciprocity requirement for domestic, non-public utilities as
for foreign utilities doing business in the United States, the
Commission will ensure that foreign entities will continue to be
treated no less favorably than domestic, non-public utilities.

V. Proposed Modifications of the OATT

A. Consistency and Transparency of ATC Calculations

    113. In Order Nos. 888 and 889, the Commission directed
transmission providers to offer their unused transfer capability to the
market and to post the amount of ATC \107\ on OASIS. At the time those
orders were issued, the Commission noted that formal methods did not
exist for calculating ATC, but recognized that there were industry
efforts underway to develop a consistent, industry-wide method for
calculating it.\108\ Instead of prescribing a specific methodology for
calculating ATC in Order Nos. 888 and 889, the Commission encouraged
the industry efforts and required that transmission providers base
their ATC calculation methodologies on current industry practices,
standards and criteria.\109\ In addition, the Commission directed
transmission providers to include a description of their ATC
calculation methodologies in Attachment C of their tariffs.
---------------------------------------------------------------------------

    \107\ See supra note 7.
    \108\ Order No. 889 at 31,607.
    \109\ Id.
---------------------------------------------------------------------------

    114. Ten years later, however, although some progress has been
made, the industry still has not developed a consistent, industry-wide
methodology for evaluating ATC. In the intervening years, the industry,
working through the North American Electric Reliability Council (NERC),
has adopted a general definition of ATC, which establishes a basic
methodology for evaluating ATC. NERC also has developed a set of
guiding principles for calculating ATC and has encouraged further
consistency of ATC calculation methodologies on a regional level. NERC
defines ATC as the transfer capability remaining on the system for
further commercial activity over and above already committed uses. This
value is determined by deducting existing transmission commitments
(ETC) \110\ (including transmission reservations, network and retail
customer service), capacity benefit margin (CBM),\111\ and transmission
reliability margin (TRM) \112\ from total

transfer capability (TTC).\113\ However, NERC's calculation methodology
is not prescriptive; it establishes a framework for evaluating ATC,
which leaves open to each transmission provider's interpretation and
discretion the specific algorithm, data inputs and assumptions needed
to assess ATC.\114\ Consequently, transmission providers have developed
numerous ways to evaluate ATC using their own algorithms, data and
modeling assumptions.\115\
---------------------------------------------------------------------------

    \110\ NERC does not have a formal definition or standard
methodology for ETC.
    \111\ NERC defines CBM as the amount of firm transmission
transfer capability preserved by the transmission provider for load-
serving entities, whose loads are located on that transmission
service provider's system, to enable access by the load-serving
entities to generation from interconnected systems to meet
generation reliability requirements. Preservation of CBM for a load-
serving entity allows that entity to reduce its installed generating
capacity below that which may otherwise have been necessary without
interconnections to meet its generation reliability requirements.
The transmission transfer capability preserved as CBM is intended to
be used by the load-serving entities only in times of emergency
generation deficiencies. See North American Electric Reliability
Council, Glossary of Terms Used in Reliability Standards, (Effective
April 1, 2005), (NERC Glossary) available at ftp://www.nerc.com/pub/sys/all_updl/standards/sar/Glossary_07Feb06.pdf
.

    \112\ NERC defines TRM as the amount of transmission transfer
capability necessary to provide reasonable assurance that the
interconnected transmission network will be secure. TRM accounts for
the inherent uncertainty in system conditions and the need for
operating flexibility to ensure reliable system operation as system
conditions change. See NERC Glossary.
    \113\ NERC defines TTC as the amount of electric power that can
be moved or transferred reliably from one area to another area of
the interconnected transmission systems by way of all transmission
lines (or paths) between those areas under specified system
conditions. See NERC Glossary.
    \114\ See NERC, Available Transfer Capability Definitions and
Determination: A Framework for Determining Available Transfer
Capabilities of the Interconnected Transmission Networks for a
Commercially Viable Electricity Market (1996) available at ftp://www.nerc.com/pub/sys/all_updl/docs/pubs/atcfinal.pdf
.

    \115\ See supra note 59.
---------------------------------------------------------------------------

    115. Although transmission providers across the Nation have
developed various methodologies, in general, there are two main
approaches to calculating ATC used in the industry. The first is the
contract path approach, which is more commonly used by transmission
providers in the Western Electricity Coordinating Council (WECC)
region.\116\ The contract path methodology derives ATC directly from
predetermined TTC, ETC, CBM, and TRM values derived consistent with
contract path transmission rights. The second method is the flowgate
\117\ approach, which is used more widely in the Eastern
Interconnection.\118\ The flowgate methodology is based on physical
power flow models. The flowgate calculation first determines AFC and
then converts AFC into ATC and derives TTC for the OASIS posting. The
differences between the two approaches may not result in significantly
different ATC values if consistent data inputs and industry acceptable
modeling assumptions are used. Without a consistent and transparent
approach to evaluating ATC, transmission customers will remain wary
when service is denied and transmission providers will be the subject
of suspicion and heightened scrutiny, especially given the increasingly
congested state of the Nation's electric grid.
---------------------------------------------------------------------------

    \116\ See, e.g., Determination of Available Transfer Capability
within the Western Interconnection (June 2001), available at http://www.wecc.biz/documents/library/procedures/ATC-apprdec01.pdf
.

    \117\ A flowgate is a designated point on the transmission
system used in the modeling of power flows. While NERC currently
does not have a formal definition for AFC, the power industry
commonly defines AFC as a measure of the capability remaining on a
flowgate for future uses, after considering the effect of prior
sales. Mathematically, the industry measures AFC as AFC = Flowgate
rating--[(base case flow)--(impacts of existing reservations)]--
FlowgateCBM--FlowgateTRM.
    \118\ See, e.g., PJM Manual 2: Transmission Service Request
(April 14, 2005), available at: http://www.pjm.com/contributions/pjm-manuals/pdf/m02v08.pdf_____________________________________-

Consistency
    116. Generally, transmission providers calculate ATC by creating a
base model of their system using a set of data inputs and assumptions,
which are determined by the transmission provider. The transmission
provider uses the model to perform various computer simulations of the
operations of its system to determine the levels of transfer capability
available on the system. The types of data and assumptions used in the
models include, for example, facility ratings, the operating status of
facilities, and generation dispatch, which might be supported by
history, transmission plans, or the judgment of the transmission
provider. For example, a transmission provider could use its judgment
to reduce a facility rating or model certain facilities as out of
service, which would have the effect of calculating a lower TTC value.
A transmission provider also may use generation dispatch assumptions to
limit transfer capability that otherwise would have been available to
independent generators, thereby favoring the transmission provider's
own generation. A transmission provider usually assumes that designated
network resources are dispatched in economic merit order. However, a
transmission provider has the discretion to decide which of the
generators that are not designated network resources will be modeled
in-service. Assumptions like these influence the loading on
transmission lines in the model and heavily influence the resulting
ATC. Having standards in place that address the calculation of ATC
components, data inputs, and modeling assumptions would help ensure
non-discriminatory treatment by limiting a transmission provider's
ability to use discretion to the disadvantage of competitors and the
market.
    117. As noted above, NERC does not have a formal definition of ETC.
Without clear criteria for what should be included in a transmission
provider's ETC, a transmission customer might not know whether ETC is
being over- or underestimated. For example, a transmission provider
could set aside more capacity for native load than is realistically
expected to occur. This could happen if a transmission provider
includes in ETC excess capacity for a load-serving entity (such as
capacity to meet generation reserve requirements) but then also has a
CBM component in its calculation of ATC that includes the same
capacity. A transmission provider also could overestimate its ETC by
double-counting the same transmission reservations in its ATC
calculation. For example, this could happen if a transmission provider
fails to replace a transmission reservation with the associated real-
time schedule, and as a result does not release non-firm ATC. A
consistent process for calculating ETC will limit the subjectivity of
the transmission provider's decisions and provide a more uniform method
for estimating ETC.
    118. With respect to the modeling of a particular transaction, when
information concerning the source is unknown, a transmission provider
has the discretion to select which generator(s) will be used as a
source.\119\ There are no standards for how that modeling should be
done and, consequently, a transmission provider could model a source
using single or multiple generators by increasing (scaling up) their
output. In general, modeling a transaction using multiple generators as
a source is less conservative for the transmission system than modeling
a transaction using a single generator as a source. Modeling a
transaction using multiple generators as a source typically results in
a higher ATC value. Conversely, when a transmission provider models a
transaction using a single generator as a source, this can result in a
lower ATC value depending on the location of the generator. Modeling of
contingency outages used for calculating ATC is another area within the
discretion of the transmission provider. Although the type of
contingency, such as single contingency (n-1), is determined by
governing reliability criteria,\120\ the transmission provider
determines which specific contingencies will be used for the ATC
calculation. The common industry practice is to consider the loss

of each transmission facility at voltage 100 kV and above. However, the
lack of standards governing transfer analysis allows the transmission
provider to use its discretion to monitor outages only of facilities at
230 kV and above, ignoring the limitations that may exist for the loss
of the facilities at lower voltages, such as 115 kV or 138 kV.
Consequently, ATC values may vary substantially, with ATC being much
higher when monitoring contingencies of facilities at 230 kV and above,
and much lower while monitoring the loss of all facilities (voltage 100
kV and above).
---------------------------------------------------------------------------

    \119\ Transmission providers do not always know the generator
used as a source of energy provided under contracts that qualify as
designated resources; the only requirement is that the network
customer have an executed contract that commits it to purchase
noninterruptible power. See Wisconsin Public Power Inc. v. Wisconsin
Public Service Corp., 84 FERC ] 61,120 at 61,650-51 (1998).
    \120\ Standard TPL-001-0, Table I. Transmission System
Standards--Normal and Emergency Conditions, NERC Reliability
Standards for the Bulk Electric Systems of North America (effective
April 1, 2005).
---------------------------------------------------------------------------

    119. Furthermore, in calculating ATC, transmission providers set
aside a portion of transfer capability in the form of CBM and/or TRM to
provide for adequate generation reserves and account for uncertainties
or contingencies, respectively. Generally, CBM is the amount of firm
transmission transfer capability held back by the transmission provider
so that load-serving entities, whose loads are located on the
transmission provider's system, can access remote generation reserve
from interconnected systems in times of emergency generation
deficiencies. Some believe it is necessary for transmission providers
to set aside a portion of their TTC to ensure that their ties with
other systems remain available for this purpose. There are no
consistent industry-wide standards, however, for determining how much
transfer capability should be set aside as CBM. There is also no common
approach to whether the capacity is set aside for Native Load
Customers, as defined in section 1.19 of the pro forma OATT, for retail
load, or for all load-serving entities. The lack of consistent criteria
and clarity with regard to the entity on whose behalf CBM has been set
aside has the potential to result in the transmission provider setting
aside capacity that it might not otherwise need to, thus increasing
costs for native load customers and blocking other firm uses of the
transmission system.\121\
---------------------------------------------------------------------------

    \121\ The Commission has explained that the pro forma OATT
requires both transmission customers and transmission providers
using the transmission system to serve network load (including
bundled retail native load) to designate their resources and loads
so that the transmission customers and transmission providers would
have no incentive to designate network resources above their needs
and, in so doing, tie up valuable transmission capacity. Aquila
Power Corp. v. Entergy Services, Inc., 90 FERC ] 61,260, reh'g
denied, 92 FERC ] 61,064 (2000), reh'g denied, 101 FERC ] 61,328
(2002), aff'd sub nom. Entergy Services, Inc. v. FERC, 375 F.3d 1204
(D.C. Cir. 2004) (Aquila).
---------------------------------------------------------------------------

    120. Similarly, TRM is the amount of transmission transfer
capability reserved by the transmission provider to ensure that the
transmission network will be secure under a reasonable range of
uncertainties in system conditions. Because TRM and CBM are both
maintained in part for the loss of generators, there exists the
possibility of double-counting reliability margins for the loss of the
same generation.
    121. Moreover, a transmission provider also can use more
conservative inputs and assumptions for calculating ATC and performing
system impact studies (that tend to minimize ATC) when it is assessing
a long-term transmission service request, but use less conservative
inputs and assumptions (that tend to maximize ATC) when it is
performing system planning for retail native load. This creates the
potential for undue discrimination where a transmission provider uses
one set of data and assumptions to evaluate third party requests and
another set of data and assumptions to plan its system to serve its own
load.
Data Exchange Among Transmission Providers
    122. The lack of a consistent ATC calculation methodology combined
with limited coordination between transmission providers can result not
only in inefficiencies but unjust and unreasonable terms and conditions
of service, especially for a customer seeking contiguous transmission
service from multiple transmission providers. The ATC values posted by
a transmission provider are often inaccurate for reasons beyond the
control of the transmission provider. A transmission provider may post
ATC values in good faith and attempt to provide transmission service
based on these values only to discover later that the transfer
capability that it thought was available no longer exists due to
decisions made by other transmission providers that it did not know
about at the time it made its calculations. Accurate ATC calculation
requires reliable and timely information about such things as load,
generation dispatch, facility outages, and transactions on neighboring
systems. Transmission providers also may apply differing assumptions
and criteria to ATC calculations, which may produce wide variations in
posted ATC values for the same transmission paths. All of these
considerations make it difficult for an individual transmission
provider that operates one part of an interconnected grid to calculate
ATC accurately.
    123. This lack of communication and coordination between
transmission providers of ATC data can also affect reliability. As
discussed above, a transmission provider could grant transmission
service without being aware of the real impact that service may have on
an adjacent transmission provider's system, thus degrading the
reliability of the interconnected system. Inaccurate ATC values can
cause overselling of transfer capability, which can lead to
curtailments or transmission loading relief (TLR) actions to avoid
exceeding thermal, voltage, and/or stability limits.
Transparency
    124. As discussed, the lack of a consistent, industry-wide
methodology for assessing ATC makes undue discrimination difficult to
detect. This problem is further exacerbated by a lack of transparency
surrounding the calculation methodology used by transmission providers.
Although the Commission requires transmission providers to file their
methodologies for calculating ATC in their tariffs, transmission
providers often have responded by filing very general narrative
descriptions of their calculation methodologies (often simply referring
to the general NERC definition) \122\ without further specification of
the mathematical algorithm, data inputs, and modeling assumptions used
to perform the calculation.
---------------------------------------------------------------------------

    \122\ See, e.g., the OATTs of Aquila, Inc., Southern, and Tucson
Electric Power Company.
---------------------------------------------------------------------------

    125. Other than the description of the ATC methodology provided in
transmission providers' tariffs, third parties often have limited
access to information concerning the specific algorithms, data and
assumptions used by transmission providers to evaluate their ATC, which
makes it difficult to verify or challenge a transmission provider's ATC
calculations. The Commission requires each transmission provider to
calculate and post ATC and TTC values for each posted path.\123\
Transmission providers also are required to make publicly available, on
request, all data used to calculate ATC and TTC for any constrained
path.\124\ Additionally, transmission providers are required to make
publicly available, on request, system planning studies or

network impact studies performed for customers to determine network
impacts. Furthermore, subsequent to Order Nos. 888 and 889, the
Commission required each transmission provider to post (and update) the
CBM value for each path for which it already posts ATC and TTC, as well
as a narrative explanation of its CBM practices.\125\
---------------------------------------------------------------------------

    \123\ See 18 CFR 37.6 (b) (2005). A posted path is defined as
any control area to control area interconnection; any path for which
service is denied, curtailed or interrupted for more than 24 hours
in the past 12 months; and any path for which a customer requests to
have ATC or TTC posted. Id. 37.6 (b)(1)(i).
    \124\ Id. 37.6 (b)(2)(ii). A constrained posted path is defined
as any posted path having an ATC value less than or equal to 25
percent of TTC at any time during the preceding 168 hours or for
which ATC has been calculated to be less than or equal to 25 percent
of TTC for any period during the current hour or the next 168 hours.
Id. 37.6 (b)(1)(ii).
    \125\ Capacity Benefit Margin in Computing Available
Transmission Capacity, 88 FERC ] 61,099 (1999) (CBM Order).
---------------------------------------------------------------------------

    126. Yet, despite these requirements, third parties often are
unable to gain access to sufficient information surrounding a
transmission provider's ATC calculation methodology. As a preliminary
matter, we note that while the OASIS requirements regarding the
availability of information related to ATC and TTC calculations are
still in effect, they have been affected by restrictions that have been
placed upon the availability of critical energy infrastructure
information (CEII) in the interest of national security.\126\
Therefore, system planning and network impact studies and models
typically are no longer available on a transmission provider's OASIS.
Furthermore, transmission customers are often unable to access other
information such as load flow base cases and associated files. In sum,
although existing Commission regulations are intended to provide a
certain level of transparency, this transparency is undermined by a
number of factors, including the absence of detailed descriptions of
the data inputs, assumptions, and criteria used to determine the data
included in ATC calculations, as well as the inability of customers to
access certain of this data because of, among other reasons, security
concerns.
---------------------------------------------------------------------------

    \126\ See Critical Energy Infrastructure Information, Order No.
630, 68 FR 9857 (Mar. 3, 2003), FERC Stats. & Regs. ] 31,140 (2003),
order on reh'g, Order No. 630-A, 68 FR 46456 (Aug. 6, 2003), FERC
Stats. & Regs. ] 31,147 (2003), order on clarification, Order No.
662, 70 FR 37031 (Jun. 28, 2005), FERC Stats. & Regs. ] 31,189
(2005); see also 18 CFR 388.113 (2005).
---------------------------------------------------------------------------

Recent Industry Efforts To Improve the Consistency and Transparency of
ATC Calculations
    127. The industry recently has taken some steps to address the lack
of consistency and transparency in the way ATC is calculated. NERC
formed a Long-Term AFC/ATC Task Force to review NERC's standards on
ATC, which issued a final report in 2005 (NERC Report) \127\ that made
recommendations for greater consistency and greater clarity in the
calculation of ATC. The task force also recommended greater
communication and coordination of ATC information to ensure that
neighboring entities exchange relevant information. Based on the
recommendations in the NERC Report, NERC has two Standards
Authorization Request (SAR) proceedings underway to revise the
standards on ATC. The first SAR proceeding proposes changes to the
existing standards on ATC to, among other things, further establish
consistency (on a regional basis) in the calculation of ATC and to
increase the clarity of each transmission provider's ATC calculation
methodology. The second SAR proceeding proposes certain changes to
NERC's existing standards on the ATC components of CBM and TRM. This
proceeding also calls for greater regional consistency and transparency
in how CBM and TRM are treated in transmission providers' ATC
calculations. Also, based on the recommendations in the NERC Report,
the North American Energy Standards Board (NAESB) has a proceeding
underway to develop business practice standards to enhance the
processing of transmission service requests, which use TTC, ATC and/or
AFC.
---------------------------------------------------------------------------

    \127\ See supra note 115.
---------------------------------------------------------------------------

    128. Following the release of the NERC Report, the Commission
issued the ATC NOI \128\ seeking comments on the contents of the NERC
Report. More specifically, the Commission sought comments on the NERC
Report's recommendations on areas in which CBM and TRM could be more
specific and whether these recommendations go far enough in promoting a
common CBM and TRM methodology within each region. The Commission also
sought comments on the definitions of ATC, AFC, CBM and TRM. The
Commission also solicited comments on the advisability of revising and
standardizing ATC, AFC, TRM and CBM values. In addition, the Commission
sought comments on the advisability of developing interconnection-wide
standards for the Eastern Interconnection and WECC. Finally, the
Commission asked for comments on the most expeditious way to obtain
industry-wide standards for ATC calculations.
---------------------------------------------------------------------------

    \128\ Supra note 9.
---------------------------------------------------------------------------

    129. Furthermore, in the NOI, the Commission sought comments on
whether undue discrimination is most likely to occur in areas such as
ATC calculation where the transmission provider retains discretion as
to how to implement a particular tariff provision.
Comments
Comments on Consistency
    130. Many commenters express general support for some level of
increased consistency in ATC calculations.\129\ Some commenters urge
the Commission to develop a consistent, industry-wide methodology for
calculating ATC.\130\ Constellation asserts that although transmission
providers need to be innovative and flexible in many respects, a
requirement that all transmission providers use the same methodology to
determine ATC would not only remedy the lack of clarity that surrounds
these calculations and reservations, but would provide regulatory
certainty and assist transmission customers in predicting the outcome
of transmission service requests. This, in turn, Constellation
suggests, would expand the commercial opportunities for transmission
customers. According to Alcoa, AWEA and Renewable Energy, the industry-
wide methodology should be a flow-based methodology, rather than a
contract path methodology because they believe that a flow-based
analysis provides a more realistic view of actual system usage and
results in a more accurate assessment of ATC. Exelon further suggests
that this uniform methodology should also apply to all transmission
providers, including RTOs.
---------------------------------------------------------------------------

    \129\ E.g., Alcoa, Ameren, AWEA, Calpine, Constellation,
Cottonwood ATC NOI Comment, ELCON, Exelon, FTC ATC NOI Comment,
Midwest ISO ATC NOI Comment, Midwest SATS, New York Commission ATC
NOI Comment, North Carolina Commission, Occidental, South Carolina
E&G, TAPS, and TransAlta.
    \130\ E.g., Alcoa, AWEA, Constellation, Exelon, Occidental, and
Renewable Energy.
---------------------------------------------------------------------------

    131. Other commenters argue against a one-size-fits-all approach,
but rather express a preference for greater uniformity at a regional
level to recognize regional differences.\131\ These commenters suggest
that due to differences in transmission systems or regions, it may not
be practical or possible to standardize the ATC calculation methodology
on an industry-wide basis. For example, Powerex cautions that
nationwide standardization may not take into account the unique
characteristics of particular systems or regions, such as the
differences attributable to the West's contract-path model and the
East's flow-based model, as well as differences attributable to the
primarily hydro-

based systems in the Pacific Northwest.\132\ Similarly, TANC argues
that flowgate terminology and application in ATC calculation should not
be required in the West because it does not adequately represent the
nature of the many transmission constraints in the West. Other
commenters caution that too much uniformity of the ATC calculation
methodology could have an adverse effect on grid reliability.\133\ In
addition, some commenters urge the Commission not to adopt an ATC
methodology that is so prescriptive that it inhibits new or better
practices or imposes a wholesale revision of accepted market designs
and processes that are working within established markets.\134\
---------------------------------------------------------------------------

    \131\ E.g., Alberta Intervenors, APPA, Bonneville, International
Transmission, ISO/RTO Council, LDWP, MidAmerican, Nevada Companies,
Powerex, Progress Energy, Public Generating Pool, Public Power
Council, Salt River, Santa Clara, Snohomish, Tacoma Power, TANC, and
TDU Systems.
    \132\ Accord LDWP ATC NOI Comment, Public Power Council, Salt
River, Snohomish, Tacoma, and TANC.
    \133\ E.g., NERC ATC NOI Comment, Public Power Council, and TVA.
    \134\ E.g., ISO/RTO ATC NOI Comment and Powerex.
---------------------------------------------------------------------------

    132. Several commenters argue against any efforts to further
standardize ATC calculations.\135\ In its comments filed in the ATC NOI
proceeding, LDWP asserts that the alleged problems with ATC are
overstated. Moreover, it argues, the benefits of squeezing additional
ATC from existing systems have not been established given that
transmission customers can already request any capacity they need
regardless of the posted ATC and transmission providers are required to
make a good-faith effort to evaluate each request. Several commenters
argue that the circumstances of individual transmission customers vary
and often ATC calculations rely on the individual transmission
provider's knowledge of its facilities and system conditions.\136\ For
example, Southern contends that too many factors go into the
calculation of ATC to make the adoption of a static set of standards
feasible. In fact, Southern and EEI maintain, standardization of ATC
calculations is inconsistent with maintaining reliability because the
circumstances of transmission providers vary significantly, and they
must operate their systems based on their specific circumstances. In
addition, LG&E maintains that standardizing ATC will not necessarily
eliminate the need for TLR procedures to deal with load forecast errors
and unplanned generation and transmission outages. Furthermore, some
commenters argue that increased uniformity could impose significant
costs upon utilities.\137\
---------------------------------------------------------------------------

    \135\ E.g., Cinergy, EEI, LG&E, LDWP ATC NOI Comment, National
Grid, PPL, Public Generating Pool, San Diego G&E, Southern, TVA, and
Xcel.
    \136\ E.g., Southern and TVA.
    \137\ E.g., International Transmission and LG&E.
---------------------------------------------------------------------------

    133. Some commenters urge the Commission to increase the
consistency of the elements of the ATC calculation, such as the kind of
data inputs that transmission providers consider when evaluating ATC--
including load levels, generator outage information, transmission
outage information and generation dispatch information.\138\ Exelon
also urges the Commission to establish the assumptions that
transmission providers use in their ATC methodologies--such as how
transmission reservations are accounted for and which reservations to
model. Exelon also cites an example of modeling transaction
counterflows, noting that uniform rules for data inputs are needed to
ensure that transaction counterflows are modeled identically in both
the planning and ATC/AFC calculation processes. In addition, commenters
urge the Commission to establish the procedures for determining ATC
(and its components) and to require a transmission provider to show
that it has properly followed all required procedures.\139\ Among other
things, commenters suggest that the Commission should establish how
frequently ATC is calculated, how frequently inputs are updated,
require transmission providers to determine AFC instead of ATC, and
require transmission providers to recognize all third-party flowgates
that are requested to be monitored. In addition, several commenters
state that the Commission should require that the methodology and
inputs for ATC calculations be consistent with the transmission
provider's planning or operating criteria.\140\
---------------------------------------------------------------------------

    \138\ E.g., Exelon and TDU Systems.
    \139\ E.g., Ameren and Exelon.
    \140\ E.g., Exelon, ISO/RTO ATC NOI Comment, MISO, and NERC.
---------------------------------------------------------------------------

    134. Several commenters urge the Commission to allow the industry,
working through NERC and NAESB, to complete efforts already underway to
further increase consistency of ATC (and its components), as well as
certain related business practices.\141\ However, many of these
commenters urge the Commission to give the industry, working through
these organizations, specific guidance on what issues to decide and the
parameters for the discussions.\142\ Furthermore, commenters state that
the Commission should establish a date certain for completion of these
industry efforts,\143\ and should also take an active role in the
process.\144\
---------------------------------------------------------------------------

    \141\ E.g., Ameren, APPA ATC NOI Comment, Duke, EEI, Exelon,
International Transmission Company ATC NOI Comment, ISO/RTO Council
ATC NOI Comment, KCP&L, MidAmerican ATC NOI Comment, MISO ATC NOI
Comment, Progress Energy, Southern, TAPS, TDU Systems, TransAlta,
and WestConnect ATC NOI Comment.
    \142\ E.g., APPA ATC NOI Comment and International Transmission
ATC NOI Comments.
    \143\ E.g., Duke and Exelon.
    \144\ E.g., APPA ATC NOI Comment, TAPS, and TransAlta.
---------------------------------------------------------------------------

    135. Other commenters suggest that the Commission should require
that an independent entity develop and/or monitor a transmission
provider's ATC methodology and its ATC calculations.\145\ For example,
Constellation states that it does not believe that the solution is to
prohibit the transmission provider entirely from exercising its
discretion, but instead to require transmission providers to retain an
independent entity that can perform certain functions on a consistent,
unbiased basis. In addition, the Arkansas Commission asserts that
section 1281 of EPAct 2005 \146\ gives the Commission the authority to
require the use of an independent coordinator of transmission to
provide independent and verifiable transparency over critical Order No.
888 functions, such as ATC calculations.
---------------------------------------------------------------------------

    \145\ E.g., Arkansas Commission, Calpine, Constellation, EPSA,
New York Commission, Occidental, and TDU Systems.
    \146\ EPAct 2005 sec. 1281(to be codified at section 220 of the
FPA, 16 U.S.C. 824t), which concerns electricity market transparency
rules.
---------------------------------------------------------------------------

    136. Several commenters specifically address the lack of
consistency in the industry on the definition and use of CBM and TRM.
For example, TAPS notes that NERC does not require any transmission
provider to reserve CBM. In addition, TAPS states, even in those
regions that use CBM, there is often no regional methodology; it is up
to the vertically integrated transmission provider to determine whether
it wants to reserve CBM at all and at which interfaces, with no
effective review of that determination. TAPS also states that TRM
should be clearly defined and, if truly required for reliability, then
all transmission providers should reserve it. According to TAPS, the
Commission should define TRM in a manner that leaves no discretion as
to whether, where, and how much capacity to set aside. EPSA also notes
that there is a disconnect between the planning and expansion processes
and the assumptions transmission providers use to calculate CBM and
TRM.
    137. TANC states that the Commission should closely examine the
necessity of CBM in ATC calculations. Bonneville argues that there
should only

be one commercial margin instead of multiple margins (TRM, CBM, and
others).
Comments on Data Exchange Among Transmission Providers
    138. Several commenters argue that the Commission should establish
standards for resolving seams issues between transmission providers
where each transmission provider uses a different methodology for
calculating ATC.\147\ Constellation and BC Transmission assert that
when different transmission providers have different methods for
determining ATC, this can lead to inefficiencies, including market
confusion, lost sales/purchase opportunities, and unnecessary
curtailments.
---------------------------------------------------------------------------

    \147\ E.g., BC Transmission, Constellation, Exelon, NY
Transmission, Renewable Energy, and TDU Systems.
---------------------------------------------------------------------------

    139. Commenters identify various elements of the ATC calculation
methodology that they argue should be more consistent. For example, BC
Transmission states that some of the elements that are calculated
differently at the seams include the level of TRM, the level of CBM,
the approach regarding the sale (or not) of TRM as non-firm capacity,
assumptions regarding controlling interchange and assumptions regarding
operating conditions. Similarly, MidAmerican in its response to the ATC
NOI suggests that greater coordination is needed on partial path
review, policies for decrementing AFC and redispatch policies. For
example, MidAmerican references problems associated with coordination
between transmission providers on partial path treatment. Specifically,
when transmission service involves a path across multiple systems, a
given flowgate may be evaluated several times by various providers on
the transmission path. Because of a lack of coordination between these
providers, AFC on the flowgate may be decremented multiple times for
the same transmission service request, and service may be denied even
when the true available capacity on the flowgate is sufficient to allow
the request to be granted. Exelon also states that certain data inputs
must be coordinated across all transmission providers in an
interconnection including load levels, transmission outages, generation
outages and generation dispatch. In addition, Exelon states, the
Commission should establish how transmission providers account for
transmission reservations in an ATC/AFC calculation.
    140. Moreover, NY Commission suggests that this problem goes beyond
the non-independent transmission providers. According to NY Commission,
in order for RTOs to properly determine tie flow limits, they need
access to certain information from the control region on the other side
such as load levels and distributions, generator dynamic capability and
expected outputs, phase shifter positions and standard contingencies
required by that control area. In addition, NY Commission states, these
inputs need to be updated daily.
    141. Finally, Alcoa states that the potential for underestimating
ATC is likely another consequence of the fundamental conflict between
the contract path model and the electricity path model of contracting
for electric energy. According to Alcoa, outside of ISO/RTO systems,
utilities may not have enough data available to compute ATC, since they
may not be able to accurately complete all relevant parallel path
transactions.
Comments on Transparency
    142. Commenters are overwhelmingly in favor of greater transparency
in the ATC calculation methodology to provide more assurance that a
transmission provider is not performing its ATC calculations in an
inconsistent or unduly discriminatory manner.\148\ EEI suggests that
transmission providers could make their base case load flow studies on
which they base their calculation of ATC available to transmission
customers, subject to security and confidentiality protections. Other
commenters state that greater transparency could be achieved through
the imposition of additional posting requirements on OASIS.\149\ These
commenters argue that the Commission should require transmission
providers to post their discrete methodologies and algorithms for
evaluating ATC, as well as their transmission modeling information and
their various assumptions. Commenters further suggest that transmission
providers should be required to provide information regarding planned
outages, and to ensure consistent treatment of outage information
between control areas.\150\
---------------------------------------------------------------------------

    \148\ E.g., Alcoa, Ameren, APPA, Calpine, CEOB, Cinergy,
Constellation, Cottonwood, Duke, EEI, ELCON, HQ Energy, LDWP,
MidAmerican, Midwest ISO, Midwest SATs, Powerex, PPL, Progress
Energy, Public Generating Pool, Public Power Council, Salt River,
Southern, TANC, TAPS, TDU Systems, TransAlta, and TVA.
    \149\ E.g., Calpine and PPL.
    \150\ E.g., H.Q. Energy and Powerex.
---------------------------------------------------------------------------

    143. In its reply comments, Southern acknowledges that greater
transparency would reduce concerns of undue discrimination, but
cautions the Commission against imposing unnecessary and duplicative
posting requirements and notes that much of the information that
commenters have asked the Commission to make transparent is in fact
already publicly available through a variety of sources.
    144. In addition, some commenters urge the Commission to impose
meaningful reporting requirements.\151\ In this regard, Constellation
asserts that the Commission should modify the pro forma OATT to require
that transmission providers post systematic, timely and accurate
reporting of certain service metrics such as transaction requests
approved, rejected, confirmed, and curtailed. Similarly, Cottonwood
states that transmission providers should be required to provide
information detailing why a particular transmission request was denied
and whether there are other available alternatives. In addition,
several commenters argue that transmission providers also should be
required to post their relevant business practices, operating
standards, protocols and internal guidelines that affect transmission
service.\152\ TDU Systems also urge the Commission to require
transmission providers to explain why transactions are allowed to flow
even when the posted ATC value was zero.
---------------------------------------------------------------------------

    \151\ E.g., Constellation, Cottonwood, and TDU Systems.
    \152\ E.g., Powerex and TransAlta.
---------------------------------------------------------------------------

    145. EPSA argues that capacity is unnecessarily held from the
market when transmission providers reserve excessive amounts for their
native load and when they fail to make capacity available through
redispatch. EPSA states, however, that there is no way of knowing
whether there is a hoarding problem because there is no requirement to
post the necessary real time information on transmission utilization,
and recommends a requirement to post such information. Powerex contends
there is an incentive for transmission providers to hoard because
grandfathered or other firm rights held by the transmission provider to
serve native load are subsequently used for wholesale marketing
purposes. It further states, however, that evidence of anticompetitive
practices is difficult to obtain because of a lack of transparency.
Powerex supports increased requirements for both uniform and
transparent ATC calculation.
    146. Several commenters urge the Commission to establish compliance
review procedures and impose sanctions for violations to ensure that
transmission providers are accountable

for ensuring that their ATC calculations are correct.\153\ In its
response to the ATC NOI, Cottonwood states that the Commission should
develop specific tests (benchmarks) to monitor transmission providers'
performance. In addition, HQ Energy states that the Commission should
conduct periodic reviews of whether non-independent transmission
providers have properly calculated and allocated ATC. ELCON states that
the Commission should place the burden of proof to depart from its ATC
methodology on the transmission provider and include specific penalties
in the tariff for transmission providers that are found to be in
violation.
---------------------------------------------------------------------------

    \153\ E.g., Cottonwood ATC NOI Comment, ELCON, HQ Energy, NRECA,
Occidental, and Powerex.
---------------------------------------------------------------------------

    147. HQ Energy and Powerex also state that the Commission should
require transmission providers to ensure that staff is available at all
times to respond to customer inquiries regarding real-time
transactions.
Discussion
    148. We propose to address the potential for remaining undue
discrimination in the determination of ATC by requiring industry-wide
consistency and transparency of certain definitions, data, modeling
assumptions and components of ATC. We propose to provide general
guidance regarding the aspects of ATC calculation that we believe
should be more consistent and direct public utilities, working through
NERC and NAESB, to use our guidance to revise the relevant standards
and business practices. In addition, we propose to require increased
detail in the pro forma OATT regarding the method of calculating ATC
and to amend our OASIS regulations to require increased transparency.
    149. Though NERC and NAESB currently are working on certain
proposals to address the problems we have identified,\154\ we are
concerned that without guidance, direction and a firm deadline, these
industry developments may not succeed due to other conflicting
priorities. We believe that the existing NERC and NAESB processes are
well-suited to achieving greater consistency in ATC calculations. It is
our expectation that NERC and NAESB will expand on the work they have
already undertaken to achieve the goals we propose to set out for them.
---------------------------------------------------------------------------

    \154\ We understand that two NERC standard authorization
requests related to ATC/ TTC/AFC and CBM/TRM were approved earlier
this year, and that drafting of the standards' revision is underway.
We further understand that NAESB has a concurrent drafting effort
underway for associated business practices that will follow a
coordinated path with the NERC process. See http://www. nerc.com/

filez/ standards/MOD-V0-Revision. html.
---------------------------------------------------------------------------

    150. We propose to take this action pursuant to our obligation
under FPA section 206 to remedy undue discrimination in the provision
of transmission service. Transmission providers in general enjoy
substantial discretion in establishing and interpreting the specific
algorithms, data, and assumptions needed to assess ATC. Though we do
not believe it is possible or necessary to entirely eliminate
discretion, unchecked discretion affords a transmission provider the
ability and opportunity to discriminate in its favor (and its
affiliate's favor) against third parties in how it calculates and
allocates ATC and, therefore, may be unjust, unreasonable, unduly
discriminatory and preferential. Transmission providers have an
incentive to understate ATC on transmission paths that would be
valuable to power sellers that are competitors to the transmission
providers' own (or their affiliates') power sales. Where transmission
congestion exists, the methodology for calculating ATC will effectively
determine whether competitors have access to the transmission grid, and
the lack of any consistent methodology for calculating ATC gives
transmission providers excessive discretion in making this
determination.
    151. The lack of consistency and detail in the determination of ATC
can facilitate undue discrimination in a variety of ways. Transmission
providers may use generation dispatch assumptions that result in
limited capacity being available to merchant generators. They also may
use different inputs and assumptions for purposes of calculating ATC
for third parties than they do for system planning for retail native
load. As noted above, a transmission provider could reduce a facility
rating or model certain facilities as out of service, which would have
the effect of underestimating TTC. In determining ETC, transmission
providers have discretion to determine the capacity needed and set
aside for native load usage. Each of these exercises of discretion has
a significant effect on ATC.
    152. The lack of transparency into how a transmission provider
calculates and allocates its ATC (including all assumptions and data
inputs) makes it difficult to detect discriminatory behavior. This lack
of transparency frustrates and increases the costs of compliance and
enforcement efforts. Many transmission providers have urged the
Commission to provide greater clarity in the rules for OATT
service,\155\ particularly given the threat of the Commission's new
civil penalty authority.
---------------------------------------------------------------------------

    \155\ E.g., Ameren, APPA ATC NOI Comments, Duke, EEI, Exelon,
International Transmission Company ATC NOI Comments, ISO/RTO Council
ATC NOI Comments, KCP&L, MidAmerican ATC NOI Comments, MISO ATC NOI
Comments, Progress Energy, Southern, TAPS, TDU Systems, TransAlta,
and WestConnect ATC NOI Comments.
---------------------------------------------------------------------------

    153. In addition to our preliminary finding that the lack of
consistent, industry-wide ATC calculation standards is unjust and
unreasonable under FPA section 206, we believe that it poses a threat
to the reliable operation of the bulk-power system. A transmission
provider needs to know how much electricity its system can carry. The
lack of a consistent, industry-wide methodology for evaluating ATC and
the lack of data sharing among transmission providers often leads to
problems in determining the appropriate ATC value. Despite a
transmission provider's good faith attempt to calculate and post
accurate ATC levels, it can find that transmission that it thought was
available on its system no longer exists because it was unaware of
decisions by other transmission providers. This, in turn, can threaten
the reliable operation of the interconnected transmission system.\156\
---------------------------------------------------------------------------

    \156\ According to NERC, ``the lack of standardization and more
ignificantly, limited coordination can negatively impact both the
market, through the need for a large number of [TLR] actions (or
curtailments in WECC) and, on occasion, reliability when even the
use of TLRs provides insufficient relief on some critical
interfaces.'' See NERC Report at 1.
---------------------------------------------------------------------------

    154. As a result of reliability effects of inconsistent ATC
calculations, our proposal for greater consistency and transparency
also is supported by our new authority under section 215 of the FPA,
which gives the Commission jurisdiction to certify an Electric
Reliability Organization (ERO) and to approve reliability standards
that are just, reasonable, not unduly discriminatory or preferential,
and in the public interest. The Commission also has authority to order
the ERO to submit a reliability standard that the Commission considers
appropriate to implement FPA section 215.\157\ On April 4, 2006, NERC
submitted an application to be certified as the ERO, as well as
proposed reliability standards.\158\ In this NOPR, we direct our
guidance to public utilities and recommend that they implement our
direction by working with NERC. However, this is not intended to
prejudge the outcome of the ERO proceeding. Though the Commission

will act independently on the reliability standards proposed by NERC in
Docket No. RM06-16-000, we believe it is prudent to provide our
guidance now on NERC's reliability standards related to ATC by
providing specific direction on what should be more consistent and a
timeframe for completion of NERC's efforts.\159\ As we indicated above,
the lack of consistency, data exchange and transparency in ATC
calculations not only can increase the opportunities for undue
discrimination but also can threaten reliability. We therefore believe
that Commission action pursuant to FPA section 215 may be appropriate
on reliability standards related to ATC calculation. Any action on
these reliability standards that is taken in Docket No. RM06-16-000
(the ERO standards rulemaking) will be coordinated and consistent with
our determinations regarding ATC calculation in this proceeding.\160\
---------------------------------------------------------------------------

    \157\ Section 215(d)(5).
    \158\ See Docket Nos. RR06-1-000 and RM06-16-000.
    \159\ In this NOPR, we direct our guidance to NERC, though the
reliability standards relating to ATC ultimately will be adopted by
the ERO.
    \160\ We note that Commission staff recently released a
preliminary assessment of the proposed ATC-related reliability
standards, stating that they ``may result in unnecessary regional
variations not justified by technical differences and inconsistent
applications.'' Staff Preliminary Assessment of the North American
Reliability Council's Proposed Mandatory Reliability Standards at 80
(May 11, 2006).
---------------------------------------------------------------------------

Consistency
    155. The Commission proposes to require public utilities, working
through NERC, to develop the standards we set forth below within 6
months of the final rule in this proceeding. Consistent with NERC's
existing efforts, we propose to require the development of standards
for: (1) ATC/AFC, TTC/Total Flowgate Capacity (TFC), ETC, CBM, and TRM
calculation methodologies, (2) data inputs, (3) modeling assumptions,
(4) ATC calculation frequency, and (5) data exchange and coordination
processes. We further propose to require public utilities, working
through NAESB, to work with NERC to identify the appropriate business
practices to complement the standards developed by NERC. We discuss
below each of the elements for which we propose to require more
consistency. We seek comment on these elements of the ATC calculation
and, in particular, whether certain elements are more susceptible to
further consistency than others and whether certain elements should be
prioritized over others because they represent the source of most
disputes between transmission providers and customers. We recognize the
need to focus on those elements of the ATC calculation that are most
susceptible to further consistency and most important in terms of
eliminating opportunities for undue discrimination.
    156. The Commission recognizes that transmission providers use
several basic types of ATC calculation methodologies (with various
permutations), and does not believe that a single ATC calculation
methodology must be applied by all transmission providers.\161\
However, we agree with commenters who argue that the amount of
discretion in the existing ATC calculation methodologies gives
transmission providers the ability and opportunity to unduly
discriminate against third parties. Accordingly, we propose to achieve
greater consistency in ATC calculations by directing the development of
consistent definitions of the components of ATC, as well as consistent
data inputs, data exchange and coordination protocols, and modeling
assumptions, as discussed further below. We believe that this level of
consistency will go a long way toward producing more coherent and
uniform determinations of ATC across a region, thereby helping to
eliminate the potential for undue discrimination.\162\
---------------------------------------------------------------------------

    \161\ For example, there are two primary ATC calculation
methodologies: The contract path approach and the flowgate approach.
See generally P 115. However, the ATC values that result from
application of either method should largely be the same if
consistent data inputs and modeling assumptions are used.
    \162\ As discussed further below, for consistency to be fully
effective, it should be coupled with increased transparency. As
such, we also propose greater transparency below.
---------------------------------------------------------------------------

    157. We propose to direct public utilities, working through NERC,
to develop consistent practices for TTC/TFC calculation methodologies.
We recognize that the NERC reliability regions have historically
calculated transfer capability using different approaches.\163\
However, we expect that guidelines can be developed for the calculation
of transfer capability that use a common approach to model power
transfers. In addition, we believe that the criteria used for
identifying flowgates and determining TTC/TFC can be more consistent.
---------------------------------------------------------------------------

    \163\ One approach models power transfers by scaling up/down the
load, a second approach scales generation up/down, and yet another
approach uses a combination of changes in load and generation.
---------------------------------------------------------------------------

    158. The Commission believes that the lack of consistency of ETC
permits too much discretion in determining how much capacity a
transmission provider sets aside for native load, including its network
customers. We believe that the development of an industry-wide
methodology can limit this discretion. Therefore, we propose to require
the development of a consistent methodology for determining the
capacity needed and set aside for native load usage. In addition, we
propose that accounting for transmission reservations in an ATC/AFC
calculation also should be more consistent. Presently, there are two
main methods in use. One method models all ``appropriate reservations''
\164\ in the power flow base case model. The other method models only
those reservations that are expected to be actually scheduled and
accounts for others by decrementing flowgate AFC. It is important for
consistency to use the same calculation technique when modeling these
types of reservations. Therefore, we propose that public utilities,
working through NERC, establish and specifically identify which
reservations they use in determining ETC.
---------------------------------------------------------------------------

    \164\ ``Appropriate reservations'' takes into account the time
frame (e.g., yearly, monthly) and ATC product (e.g., firm, non-firm)
being calculated.
---------------------------------------------------------------------------

    159. The Commission has previously addressed the lack of a
consistent industry-wide methodology for determining CBM. Following a
two-day technical conference, the Commission held in the CBM Order
\165\ that transmission providers continue to wield significant
latitude in interpreting how CBM is determined. The Commission directed
that the CBM set-aside be more transparent, more accurate, and more
widely available.\166\ We remain concerned, however, that transmission
providers have preferential access to the interface capacity that is
set aside. This interface capacity is paid for by all transmission
customers whether or not they receive a benefit from the set-aside. In
general, we believe that the latitude associated with CBM undermines
the certainty and transparency that is needed for non-discriminatory,
open-access transmission service.
---------------------------------------------------------------------------

    \165\ Capacity Benefit Margin in Computing Available
Transmission Capacity, 88 FERC ] 61,099 (1999) (CBM Order).
    \166\ CBM Order at 61,237-38.
---------------------------------------------------------------------------

    160. The current pro forma OATT offers two means of reserving
transfer capability, either of which implicitly provides some financial
discipline to overreservations. The first is the requirement to
designate a network resource on the other side of the interface and
assume the associated financial responsibility of either owning the
resource or executing a firm power purchase agreement. The other is to
contract for firm point-to-point service on the interface, which
requires the payment of a point-to-point reservation charge. In either
case there is a disincentive to reserving transfer capability simply to
prevent someone else from using it on a firm basis. With

these processes in mind, the Commission has identified three possible
options to provide the necessary certainty, transparency, and financial
discipline necessary to remedy the potential for undue discrimination
associated with inappropriate ATC set-asides for CBM. These options
need not be mutually exclusive.
    161. One option is to require that clear standards be developed for
how the CBM value should be determined and allocated across
transmission paths, and for which customers CBM should be used.\167\
Consistent with the standards development process that is already in
progress, we propose that these standards specify how CBM should be
reserved to allow any load-serving entity to meet generation
reliability criteria on a nondiscriminatory basis. In addition, we
propose that NERC specify emergency generation deficiency conditions
during which a load-serving entity will be allowed to use the transfer
capability reserved as CBM. We believe that CBM should be reserved only
when there is insufficient local generation capacity to meet generation
reliability standards, and it should always have a zero value in the
calculation of non-firm ATC.
---------------------------------------------------------------------------

    \167\ NERC has already contemplated developing a standard to
address CBM issues. See http://www.nerc.com/~filez/standards/MOD-V0-Revision.html
.

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

    162. Another approach may be to develop a specific charge for
setting aside ATC for CBM. This approach would treat CBM as a service
that would be available to customers serving load within the
transmission provider's service area. To do this, the Commission would
propose that an entity for which transfer capability has been set aside
to meet generation reliability criteria be charged a separate rate for
this service. We seek comment on this proposal to charge a separate
rate, as well as comment on the potential impacts on overall rates and
revenues. We also seek comment on whether there are credible situations
in which the proposal would not be feasible. Commenters are encouraged
to provide specific examples.
    163. A third option may be to eliminate CBM and replace it with
specific transfer capability reservations associated with designated
network resources. In several cases, the Commission addressed instances
when transmission providers had taken advantage of their ability to
preserve interface capability to serve their own load while limiting
the ability of competing suppliers to access customers on their
systems. In these orders, the Commission position was that if a utility
wanted to use firm transmission capacity on an interface to serve its
native load, it was required to designate a network resource associated
with that capacity on the other side of the interface pursuant to the
requirements of the pro forma OATT.\168\ Specifically, the Commission
stated that the pro forma OATT requires the transmission provider to
designate all network resources, including those acquired for the
purpose of meeting generation reserves, in the same manner as network
customers do.\169\ The retention of this obligation would require the
transmission provider to replace any existing set-aside of firm
transfer capability as CBM with reservations for specific designated
resources. We seek comment on the reasonableness of eliminating CBM and
any impacts on the reliable operation of the transmission system.
Commenters are encouraged to provide specific examples of transmission
providers that currently do not use CBM and, alternatively, conditions
under which CBM must be used. We also ask for comments on how
eliminating CBM would affect the ability of load-serving entities to
meet existing generation reliability adequacy requirements.
---------------------------------------------------------------------------

    \168\ See Aquila supra note 121; see also Morgan Stanley Capital
Group v. Illinois Power Co., 83 FERC ] 61,204, clarified, 83 FERC ]
61,299 (1998), order on reh'g, 93 FERC ] 61,081 (2000).
    \169\ Wisconsin Public Power Inc. SYSTEM v. Wisconsin Public
Service Corp., 83 FERC ] 61,198 at 61,857-58 (1998).
---------------------------------------------------------------------------

    164. The Commission proposes that public utilities, working through
NERC, develop clear standards for how TRM is determined, allocated
across transmission paths, and used. In addition, we propose to require
that the standards ensure that there will be no contingency double-
counting when calculating TRM, TTC and CBM. We also propose that the
standards developed should specify the uncertainties that are accounted
for in TRM and the methods used to determine their impacts on TRM
values. The Commission proposes that TRM can be used to accommodate
uncertainties such as: (1) Load forecast and load distribution error,
(2) variations in facility loadings, (3) uncertainty in transmission
system topology, (4) loop flow impact, (5) variations in generation
dispatch, including intermittent resources, (6) automatic sharing of
reserves, and (7) other uncertainties identified through the NERC
forums.
    165. The Commission acknowledges that accurate data and system
models are essential to accurately simulate the performance of the
electric system when calculating ATC. The data and models used by the
transmission provider should be consistent, to the maximum extent
practicable, with the data and models used for the planning, operation,
and expansion of the transmission system. While NERC's current ATC-
related standards (MOD-001--MOD-009) require that steady state and
dynamic data be submitted and that steady state and dynamic system
models be prepared, there is no requirement to periodically benchmark
these models and appropriately modify them against actual system
events.\170\ Therefore, the Commission proposes that public utilities,
working through NERC, modify the ATC-related standards to incorporate a
requirement for the periodic review and modification of these models
(including load flow base cases, short circuit data, transient and
dynamic stability simulation data, contingency,\171\ subsystem and
monitoring files, and production cost models), in order to ensure that
they are up to date.
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    \170\ See U.S.-Canada Power System Outage Task Force, Final
Report on the August 14, 2003 Blackout in the United States and
Canada: Causes and Recommendations, Recommendation Number 24 (April
2004). See http://reports.energy.gov/.

    \171\ Contingency files should contain information on special
protection schemes and remedial action plans.
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    166. Modeling assumptions are a crucial element in the calculation
of ATC. The Commission proposes that public utilities, working through
NERC, develop consistent assumptions for use in ATC determinations. The
Commission proposes that the assumptions used in the calculation of ATC
be made consistent among transmission providers, to the maximum extent
practicable. In general, the Commission believes that the assumptions
used in the determination of ATC should be consistent with those used
when planning the operation and expansion of the transmission system.
This is necessary to remedy the potential for undue discrimination
between the manner in which a transmission provider plans and operates
its system to serve native load and the manner in which it calculates
ATC for service to third parties. Consequently, the models for short-
and long-term ATC calculation should be developed using consistent
assumptions regarding the load level, generation dispatch, transmission
and generation facilities maintenance schedules, contingency outages
and topology as those used in the planning for operation and expansion.
In addition, the long-term ATC models should rely to the maximum extent
practicable upon the

same assumptions regarding new transmission and generation facilities
additions and retirements as those used in the planning for expansion.
    167. More specifically, the Commission proposes to direct public
utilities, working through NERC, to establish consistent assumptions
that are related to the modeling of: (1) Representative load levels,
(2) generation dispatch, (3) transmission reservations and (4)
counterflows, in addition to any other modeling assumptions identified
by NERC. Regarding the assumptions used for load level modeling in the
ATC calculation, the Commission proposes to require all transmission
providers to have a consistent approach to modeling of load levels.
With respect to the base generation dispatch, we propose that public
utilities, working through NERC, establish a method for determining
which generators should be modeled in service, including guidance on
how independent generation should be considered. With respect to
modeling of particular transactions, the Commission believes that a
consistent approach is needed on how to simulate power flows from
points of receipt to points of delivery when sources are unknown.
Accounting for transmission reservations in an ATC/AFC calculation also
should be consistent.\172\ We note that the purpose of more consistent
modeling assumptions is to eliminate discretion and the potential for
undue discrimination. This proposal is not intended to change the
manner in which native load customers are served. We seek comment on
whether (and, if so, how) this proposal would affect service to native
load customers.
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    \172\ Currently, one method models all appropriate reservations
in the power flow base case model, when another models only those
reservations that are expected to be scheduled, and accounts for
others by decrementing flowgate AFC.
---------------------------------------------------------------------------

    168. The Commission also supports the development of clear
standards on how often ATC/AFC and its individual components are
calculated and updated. The Commission proposes that public utilities,
working through NERC and NAESB, develop standards requiring that the
calculation be performed on a consistent time interval among
transmission providers and in a manner that closely reflects the actual
topology of the system concerning generation and transmission outages,
load forecast, interchange schedules, transmission reservations,
facility ratings, and other necessary data. The Commission also
supports uniform updating of ATC values and components by adjacent
control areas.
    169. The Commission believes 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. Therefore, we propose that public
utilities, working through NERC, develop consistent protocols that
would enable and require the exchange of data among transmission
providers. We propose that the following data, at a minimum, should 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 calculation frequency, and (7) source/sink
modeling identification. In addition, NERC may identify other data
needs through the standards development process. We seek 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.
    170. In order to facilitate the process for achieving consistency
in ATC calculations we have proposed in this NOPR, the Commission
directs Staff to hold a technical conference. The technical conference
will be transcribed to provide the Commission and NERC a record of the
comments received at the conference. The Commission will provide
further guidance regarding the date of the technical conference and the
topics it intends to address at the technical conference in a
subsequent notice.
Transparency
Pro forma OATT
    171. Though the Commission's requirement that a transmission
provider describe its ATC calculation methodology in its OATT has not
changed, that requirement has been interpreted in various ways. Some
transmission providers post a detailed explanation of how they
calculate ATC, while other transmission providers post very general
descriptions that fail to offer sufficient detail for third parties to
understand how ATC has been derived. The Commission is concerned that
the lack of transparency in some of the descriptions provided by
transmission providers gives these transmission providers too much
discretion to change ATC practices without sufficient oversight and
review. The Commission also is concerned that this lack of transparency
could allow transmission providers to unduly discriminate against their
competitors when allocating transmission service. We agree with
commenters that greater transparency is needed into how transmission
providers calculate and allocate ATC. Accordingly, in order to ensure
that transmission service is provided in a nondiscriminatory manner, we
propose to require transmission providers to take certain measures to
make their ATC calculation process more transparent. We believe that
these proposed changes will give transmission customers access to
sufficient information to be able to examine the integrity of the
process. Moreover, our proposal for greater consistency in the way ATC
is calculated should aid in transparency because there will be far
fewer differences in the way individual transmission providers
calculate ATC. This will make it less difficult to determine whether
ATC is being calculated in an unduly discriminatory manner.
    172. Specifically, we propose to require transmission providers to
include, at a minimum, in Attachment C of their OATT, the following
information concerning their ATC calculation methodology (including the
calculation of AFC, if applicable). First, we propose to require
transmission providers to state their specific mathematical algorithm
used to calculate their firm and non-firm ATC (and AFC, if applicable)
for their scheduling horizon (same day and real-time), operating
horizon (day ahead and pre-schedule) and their planning horizon (beyond
the operating horizon). Second, we propose that transmission providers
provide a process flow diagram that illustrates the various steps
through which the ATC/AFC is calculated.
    173. In addition, we propose to require transmission providers to
include in Attachment C a detailed explanation of how each of the ATC
components is calculated for both the operating and planning horizons.
Thus, for TTC, a transmission provider should: (1) Explain its
definition of TTC; (2) explain its TTC calculation methodology (e.g.,
load flow, short circuit, stability, transfer studies); (3) list the
databases used in its TTC assessments; and (4) explain the assumptions
used in its TTC assessments regarding load levels, generation dispatch,
and modeling of planned and contingency outages.

    174. For ETC, we propose to require a transmission provider to
explain: (1) Its definition of ETC; (2) the calculation methodology
used to determine the transmission capacity to be set aside for native
load and non-OATT customers; (3) how point-to-point service requests
are incorporated; (4) how rollover rights are accounted for; and (5)
its processes for ensuring that non-firm capacity is released properly
(e.g., when real time schedules replace the associated transmission
service requests in its real-time calculations). With regard to (5), we
seek comment on whether transmission providers currently are keeping
track of when firm service reservations are not scheduled and should be
released as non-firm.
    175. If a transmission provider uses an AFC methodology to
calculate ATC, we propose to require it to explain: (1) Its definition
of AFC; (2) its AFC calculation methodology (e.g., load flow, short
circuit, stability, transfer studies); (3) its process for converting
AFC into ATC; (4) what databases are used in its AFC assessments; (5)
the assumptions used in its AFC assessments; and (6) the reliability
criteria used for contingency outages simulation.
    176. For TRM, we propose to require a transmission provider to
explain: (1) Its definition of TRM; (2) its TRM calculation methodology
(e.g., its assumptions on load forecast errors, forecast errors in
system topology or distribution factors and loop flow sources); (3) the
databases used in its TRM assessments; (4) the conditions under which
the transmission provider uses TRM; and (5) the process used to prevent
double-counting of contingency outages used in its TTC and TRM
calculations. We propose to require transmission providers that do not
reserve TRM to reflect that in Attachment C. We seek comment on the
above proposal, specifically on what type of showing a transmission
provider could make with regard to the process used to prevent double-
counting.
    177. Furthermore, in the CBM Order, the Commission required
transmission providers to post a specific and self-contained narrative
explanation of their CBM practices, including who performs the
assessment (transmission or merchant staff), the methodology used to
perform generation reliability assessments (e.g., probabilistic or
deterministic), whether the assessment method reflects a specific
regional practice, the assumptions used in those assessments and the
basis for the selection of paths on which CBM is set aside. In
addition, the Commission directed transmission providers to post their
procedures for allowing CBM during emergencies (with an explanation of
what constitutes an emergency, the entities that are permitted to use
CBM during emergencies and the procedures which must be followed by the
transmission providers' merchant function and other load-serving
entities when they need to access CBM). The Commission further stated
that if a utility's practice was not to reserve CBM, it should reflect
that in Attachment C. We propose to require transmission providers to
include this narrative in Attachment C of their OATTs.
    178. In addition, for CBM, we propose to require a transmission
provider to: (1) Explain its definition of CBM; (2) list the databases
used in its CBM calculations; and (3) prove that there is no double-
counting of contingency outages when performing CBM calculations.
    179. Though we are proposing to require transmission providers to
provide greater clarity in the description of their ATC calculations,
it is our expectation that the reforms we propose for greater
consistency of ATC methods will minimize the burden on transmission
providers and customers of assessing various ATC calculation
methodologies. Ultimately, when the ATC standards development process
we propose is completed, we expect that Attachment C will refer to the
NERC standards and will differ by transmission provider only with
respect to the limited elements of the ATC calculation that may not
have been made consistent.
OASIS
    180. The Commission's existing regulations require certain ATC-
related information to be posted on each transmission provider's OASIS,
while other information is required to be provided on request. To
ensure that relevant information is available on a timely basis to all
market participants, we propose to amend our 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.\173\ We believe that our proposed reforms will not only
enhance the amount and accuracy of information available to customers,
but will also increase the ability of the Commission and others to
detect any potentially unduly discriminatory behavior in a transmission
provider's calculation and allocation of ATC.
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    \173\ See 18 CFR 37.2 (2005).
---------------------------------------------------------------------------

    181. Our regulations state that a transmission provider's \174\ ATC
and TTC calculations shall be performed according to consistently
applied methodologies referenced in the transmission provider's OATT
and shall be based on current industry practices, standards and
criteria.\175\ We propose to revise this provision to include
compliance with the reliability standards developed by the ERO--i.e.,
ATC and TTC calculations shall be performed according to consistently
applied methodologies referenced in the transmission provider's OATT
and shall be based on the ERO reliability standards as well as current
industry practices, standards and criteria.
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    \174\ We note that various provisions of the OASIS regulations
use the term ``Responsible Party,'' which means the transmission
provider or an agent to whom the transmission provider has delegated
the responsibility of meeting any of the requirements of the
regulations. For simplicity, however, we will use the term
``transmission provider'' here.
    \175\ See 18 CFR 37.6(b)(2)(i) (2005).
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    182. The regulations further state that, on request, a transmission
provider must provide all data used to calculate ATC and TTC for any
constrained paths.\176\ Transmission providers also are required to
make any system planning studies or specific network impact studies
performed for customers to determine network impacts publicly available
on request and to post a list of such studies on the OASIS.\177\ The
Commission proposes to maintain these requirements.
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    \176\ See 18 CFR 37.6(b)(2)(ii) (2005).
    \177\ See 18 CFR 37.6(b)(2)(iii) (2005).
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    183. The Commission's OASIS regulations require transmission
providers to calculate and post ATC and TTC for each posted path.\178\
The regulations define two classes of posted paths based on usage:
``constrained'' and ``unconstrained.'' A constrained posted path is any
posted path for which ATC has been less than or equal to 25 percent of
TTC at any time during the preceding 168 hours or is calculated to be
less than, or equal to, 25 percent of TTC for any period during the
current hour or the next 7 days. An unconstrained posted path is any
posted path that is not a constrained posted path.\179\ The Commission
proposes to amend the regulations relating to the data posted for
constrained posted paths, but largely to retain the existing

posting requirements for unconstrained posted paths, as set forth
below.
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    \178\ See 18 CFR 37.6 (2005).
    \179\ See 18 CFR 37.6(b)(1)(iii) (2005). Our regulations require
transmission providers to post ATC and TTC for specific time
horizons for constrained posted paths and unconstrained posted
paths. The Commission proposes to maintain the existing time
horizons. See 18 CFR 37.6(b)(3)(i)-(ii) (2005).
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    184. First, in the CBM Order, 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. The Commission proposes to incorporate
these CBM posting requirements into its regulations.
    185. With respect to paths for which the utility already posts ATC,
TTC, and CBM, we further propose to require each transmission provider
to also post (and update) the TRM value for that path.
    186. Our 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. We do not believe that this regulation has resulted in
sufficient information to determine why ATC values changed. To provide
a transmission customer with useful information to assist with its
evaluation of monthly and yearly firm transmission service options, we
propose to supplement the existing regulations by requiring the
transmission provider to post a brief, but specific, narrative
explanation of the reason for the posted change in the monthly and
yearly ATC values on a constrained path. This narrative would describe,
for example: (1) Scheduling of planned outages and occurrence of forced
transmission outages; (2) de-ratings of transmission facilities; (3)
scheduling of planned generation outages and occurrence of forced
generation outages; (4) changes in load forecast, (5) changes in new
facilities in-service dates, or other events or assumption changes that
cause the ATC value to change. We seek 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. We seek comment on whether a similar
narrative also should be required when ATC remains unchanged at a value
of zero for some specified period of time.
    187. We propose to maintain the requirement in 18 CFR Sec.
37.6(e)(2)(i) that a transmission provider must post the reason for a
denial of a request for service. We propose, however, to amend this
provision to require a transmission provider to maintain and make
available information supporting the reason for the denial for five
years. In addition, we propose to extend the time period for which
transmission providers must maintain transmission service information
for audit. Our regulations currently require audit data to be retained
and made available upon request for download for three years from the
date when they are first posted.\180\ We propose to change the period
from three to five years.
---------------------------------------------------------------------------

    \180\ See 18 CFR 37.7(b) (2005).
---------------------------------------------------------------------------

    188. 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). Thus, the Commission 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. We propose to incorporate
these requirements in the Commission's regulations and to obligate
transmission providers to reevaluate the CBM set aside at least
quarterly.
    189. We also propose to require the transmission provider and
network customers to use the transmission provider's OASIS to request
designation of a new network resource and to terminate the designation
of a network resource. As with other transmission request information
posted on OASIS, the transmission provider should keep designation and
termination information posted on OASIS for 90 days and should make
designation and termination information available upon request for five
years, consistent with 18 CFR 37.7(b) (2005). Transmission customers
will be able to query requests to designate and terminate a network
resource under 18 CFR 37.6(a)(6)(2005). We propose to require the
transmission provider to post on its OASIS a list of its current
designated network resources and all network customers' current
designated network resources. The list of network resources should
include the name of the resource, its geographic and electrical
location, and the amount of capacity from the unit to be designated as
a network resource.
    190. Finally, we remind transmission providers that transfer
capability associated with transmission reservations that are not
scheduled in real time must be included in non-firm ATC and posted on
OASIS.\181\
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    \181\ Our regulations require non-firm ATC and TTC for
constrained posted paths to be posted in the same manner as firm ATC
and TTC, except that monthly and seasonal capability need only be
posted if requested. See 18 CFR 37.6(b)(3)(i)(B)(2005).
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CEII
    191. Shortly after the attacks on September 11, 2001, the
Commission removed from public viewing certain documents that were
likely to contain detailed specifications of critical infrastructure
facilities. CEII is information concerning proposed or existing
critical infrastructure (physical or virtual) that: (1) Relates to the
production, generation, transportation, transmission, or distribution
of energy; (2) could be useful to a person in planning an attack on
critical infrastructure; (3) is exempt from mandatory disclosure under
the Freedom of Information Act, 5 U.S.C. 552 (2000); and (4) does not
simply give the location of the critical infrastructure. Accordingly,
access to transmission-related information collected by the Commission
has been restricted by the Commission's CEII regulations. Thus, for
example, information filed in FERC Form No. 715 (including base case
power flow data and transmission system maps) as well as system
planning and network impact studies and models are no longer publicly
available. However, requesters with a particular need (such as
transmission customers and consultants with legitimate needs) have the
opportunity to access information designated as CEII from the
Commission by submitting a request to the Commission under the
procedures set forth in our regulations. In Order No. 643,\182\ the
Commission addressed situations in which its regulations require public
utilities to disclose information directly to the public. The
Commission ruled that potential CEII disclosed directly from the public
utility to the public should be evaluated under the same rules
addressing the disclosure of CEII from the Commission to the public,
i.e., if an entity concludes that certain of its information is CEII,
it must designate it as such and provide other specified information
about obtaining access to the CEII through the Commission's process.
The Commission also held that it did not intend to restrict an entity's
ability to reach appropriate arrangements for sharing CEII, and that
all persons with a legitimate need for CEII should be able to gain
access to it with a minimum of difficulty.\183\
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    \182\ Amendments to Conform Regulations with Order No. 630,
Order No. 643, 68 FR 52089 (Sep. 2, 2003), FERC Stats. & Regs. ]
31,149 (2003).
    \183\ Id. at P 16.
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    192. We believe that much of the information we propose to require
transmission providers to provide in this proposed rulemaking will not
pose CEII concerns. If commenters believe

that any of the information is CEII, they should explain the basis for
that view. We recognize that requiring interested persons to use the
existing CEII process to access information we propose to require
transmission providers to provide in this rulemaking could undermine
our goal of providing increased transparency to information necessary
to evaluate the use of the transmission system. As a result, we seek
comment on procedures that could be adopted by transmission providers
to streamline the resolution of CEII concerns and allow timely
disclosure of information from the transmission providers to interested
persons.
Additional Data Posting
    193. Notwithstanding our proposed reforms requiring greater
consistency of and increased transparency into ATC calculation
methodologies, certain aspects of ATC calculation may remain committed
to the discretion of the transmission provider. Thus, we believe that
additional reporting requirements may be necessary to detect undue
discrimination. Accordingly, we propose to add a requirement in our
regulations for transmission providers to post on OASIS certain metrics
related to the provision of transmission service under the pro forma
OATT. Specifically, we propose to require transmission providers to
post data each month concerning transmission service requests
associated with particular paths or flowgates that would clearly
identify the number of requests that have been accepted and the number
of requests that have been denied during the prior month. The posted
data would show: (1) The number of non-affiliate requests for
transmission service that have been rejected and (2) the total number
of non-affiliate requests for transmission service that have been made.
This posting would distinguish between the length of the service
request (e.g., short-term or long-term requests) and between the type
of service requested (e.g., firm point-to-point, non-firm point-to-
point or network service). We also propose that the transmission
provider post similar information for affiliate transactions. In other
words, the transmission provider would also post: (1) The number of
affiliate requests for transmission service that have been rejected,
and (2) the total number of affiliate requests for transmission service
that have been made. Similarly, this posting would distinguish between
the length of the service request (e.g., short-term or long-term
requests) and between the type of service requested (e.g., firm point-
to-point, non-firm point-to-point or network service).
    194. Another area of discretion is the load forecasts used by the
transmission provider when computing ATC. The Commission recognizes
that the lack of transparency regarding transmission providers'
forecasted and actual use of the transmission system makes it difficult
to determine whether an appropriate amount of capacity is being set
aside for service to native load. To address this concern, we are
considering additional posting requirements. For example, should
transmission providers make available their underlying load forecast
assumptions for all ATC calculations? In addition, should transmission
providers post, on a daily basis, their actual daily peak load for the
prior day? We believe that this posting of forecasted and actual loads
would allow the Commission and others to make a meaningful comparison
of these elements. We invite comment on whether this information would
be helpful for such a comparison. We also seek comment on the overall
benefits of posting metrics and on potential alternative metrics.
    195. For all of our proposed OASIS reforms, we propose to require
public utilities, working through NAESB, to develop standards for
consistent methods of posting the new requirements on OASIS so that a
common format is used.

B. Transmission Planning--Coordinated, Open and Transparent Planning

    196. Order No. 888 set forth certain minimum requirements for
transmission system planning. For example, the pro forma OATT requires
transmission providers to plan for the transmission needs of their
network customers on a comparable basis (section 28.2), and it requires
them to expand their systems to accommodate firm point-to-point
customer requests (sections 13.5 and 15.4) that cannot be satisfied due
to transmission constraints or satisfied more economically via
redispatch. In addition, in Order No. 888-A, the Commission encouraged
utilities to engage in joint planning with other utilities and
customers and to allow affected customers to participate in facilities
studies to the extent practicable. The Commission also encouraged
regional planning so that the needs of all participants are represented
in the planning process.\184\ However, the Commission did not require
joint planning between transmission providers and their customers or
between transmission providers in a given region,\185\ nor did it
impose any specific requirements regarding the manner in which
transmission providers should coordinate their transmission system
planning with their pro forma OATT customers. The only section of the
pro forma OATT that directly speaks to joint planning is section 30.9,
which provides that for facilities constructed by a network customer,
the network customer must receive credit where such facilities are
jointly planned and installed in coordination with the transmission
provider.\186 \
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    \184\ See Order No. 888-A at 30,311.
    \185\ See id.
    \186\ Pro forma OATT section 21.2, ``Coordination of Third-Party
System Additions,'' provides for certain rights for transmission
providers to coordinate construction of facilities on their systems
associated with point-to-point customer requests and related
construction on a third-party transmission system, but imposes no
obligation on transmission providers.
---------------------------------------------------------------------------

    197. In the NOI, the Commission asked several questions about joint
planning between transmission providers and their customers. For
example, we asked whether joint planning should be made mandatory,
particularly when transmission requests affect adjacent transmission
systems. We also inquired whether joint planning should be subject to
an annual reporting requirement or audits. Additionally, we asked for
comment on a number of issues designed to determine whether any pro
forma OATT reforms are necessary to ensure that the transmission system
is expanded so that customers have adequate transmission service. As
the comments below indicate, commenters generally all believe that
joint and regional planning are necessary and desirable, but there is a
split over whether it should continue to be voluntary or should be made
a requirement.
Comments Supportive of Mandatory Joint and Regional Planning
    198. A number of commenters contend that joint planning between
transmission providers and their customers should be required by the
pro forma OATT. Most of these commenters also advocate joint planning
among transmission providers in a given region. In perhaps the
strongest comments on the topic, TDU Systems and TAPS request that the
Commission mandate an open, regional transmission expansion planning
process that provides opportunities for transmission customers to join
and participate in the planning process. Many other commenters also
support joint and regional planning in some form or

another, with some focusing particularly on requiring such planning
when adjacent transmission systems are affected.\187\ Bonneville and
Williams also assert that there is already Commission precedent for
joint planning in our procedures on large generator interconnections,
which require the coordination of studies when interconnection requests
affect other systems. EPSA states that the Commission should require
that neighboring systems formalize the process under which broad
regional models are developed and used to study requests on any system
within a broadly defined region. Powerex points out that the lack of
regional transmission planning is one of the most difficult issues
faced in the Pacific Northwest, and PPL asserts that transmission
planning and expansion in the Western Interconnection does not support
a competitive market.
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    \187\ E.g., AEP, Alcoa, APPA, Bonneville, Calpine, EPSA,
Lafayette, National Grid, NCPA, NRECA, Old Dominion, Trans-Elect,
Williams, and Xcel. Though it does not generally support mandatory
joint and regional planning, EEI recommends that the Commission
modify the pro forma OATT to address planning when transmission
requests require upgrades on or otherwise adversely affect adjacent
transmission systems.
---------------------------------------------------------------------------

    199. In addition, many commenters contend that transmission
providers should be required to report on an annual basis the joint and
regional planning that has occurred or been requested.\188\ TAPS states
that an annual filing notice by the Commission that gives the public an
opportunity to comment should be buttressed with audits, in order to
ensure that transmission providers are taking joint planning with their
network customers (and neighboring systems) seriously. EPSA likewise
contends that transmission providers should be required to report to
the Commission on an annual basis the joint planning that has occurred
or been requested on their systems, and that the Commission should
conduct audits to determine the level of compliance with any joint
planning requirement or agreement.
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    \188\ E.g., East Texas Cooperatives, EPSA, FMPA, MidAmerican,
and TAPS.
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    200. The commenters that advocate mandatory joint and regional
planning assert that it is needed because transmission providers unduly
discriminate against their customers when planning their transmission
systems. For example, a number of commenters assert that transmission
providers meet their own needs for transmission planning and
construction before (and often without) meeting those of their
customers.\189\ NRECA asserts that since the implementation of Order
No. 888, a number of public utility transmission providers--despite
clearly stated obligations in the pro forma OATT--have not planned for
their load-serving transmission customers on a basis comparable to that
of their own bundled retail native load. TDU Systems believes that
joint and regional transmission planning is a critical component of
ensuring comparability between a transmission provider's use of the
transmission system and a network customer's use of the transmission
system, largely because transmission providers have an incentive to
thwart the expansion planning process. Both NRECA and TDU Systems argue
that the planning processes in RTOs and ISOs also are insufficient
because they often only allow customer input after transmission plans
are developed by individual transmission providers.
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    \189\ E.g., FMPA, Midwest Municipals, NCPA, and NRECA.
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    201. TAPS asserts that the absence of joint planning has resulted
in unduly discriminatory transmission service. For comparable service
to be a reality, TAPS asserts that the transmission system must be
planned and built for customer needs, just as it must be planned and
built to meet the transmission providers' need to provide service to
their native loads. Old Dominion contends that transmission providers
often locate transmission in such a way that it favors their own
generation. According to Lafayette, transmission providers have
increased their generation dominance by inadequately planning for the
needs of their transmission customers so that they are unable to turn
to alternative suppliers. East Texas Cooperatives also argues that some
transmission providers continue to plan their systems in isolation from
the needs of other load-serving entities. EPSA concludes that the
transmission needs of non-transmission provider customers are simply
not integrated effectively into the planning process. APPA notes that
the original goal of the pro forma OATT--an inclusive planning process
that takes into account on a comparable basis the load growth and new
generation resource needs of all loads served using the transmission
provider's system--has not been achieved. Many commenters assert that
joint and regional transmission planning is necessary in order to
ensure adequate infrastructure development.\190\ Others focus on the
need for joint and regional planning to address the fact that changes
on one system often affect transmission service on adjacent
systems.\191\ Lastly, APPA blames substantial and rising congestion
costs on inadequate transmission planning, and EPSA contends that
better transmission planning is needed to support a competitive
electricity market.
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    \190\ E.g., AEP, Calpine, Constellation, East Texas
Cooperatives, ELCON, NRECA, and TransAlta.
    \191\ E.g., Alcoa and EPSA. EEI acknowledges the planning
difficulties that arise when a transmission request on one system
causes the need for upgrades to another system.
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Comments Supportive of Voluntary Joint and Regional Planning
    202. Another large group of commenters, including many investor-
owned utilities, stress that joint and regional planning, while
laudable, should not be mandatory and that it should continue to be
voluntary or that processes are already in place to encourage regional
planning.\192\ Progress Energy, for example, contends that there are
several formalized processes in place today that foster joint and
regional planning, such as the process in North Carolina. Southern
points out that in addition to participating in Southeastern Electric
Reliability Council (SERC) planning activities, it is engaged in other
types of joint regional planning (e.g., through the Georgia Integrated
Transmission System (Georgia ITS)).\193\ Nevada Companies supports the
approach already used in the WECC, which employs interconnection-wide
models for planning. Nevada Companies explains that these studies are
then made available to all other WECC transmission providers. In
addition, APS, Tacoma, and WAPA point to numerous forums (e.g., the
Southwest Area Transmission planning group and the Southwest
Transmission Expansion Plan process) where transmission providers and
other industry stakeholders coordinate their transmission plans. LPPC
also states that the Georgia ITS has provided benefits to participants
and the region--in the form of improved investment in infrastructure
and through the introduction of new sources of capital.

Lastly, some commenters point out that collaborative regional planning
already occurs in RTO and ISO regions.\194\ With regard to PJM,
however, TDU Systems argues that better transmission planning is
required due to PJM's ``rubber-stamping'' of transmission provider
identified transmission upgrades. Exelon states that the Northeastern
ISO/RTO Planning Coordination Protocol is a formal agreement, executed
in 2004, among the PJM Interconnection, the New York Independent System
Operator, and ISO New England, pursuant to which the three
organizations conduct a comprehensive process of coordinating system
planning activities.
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    \192\ E.g., Cinergy, Entergy, KCP&L, LPPC, MidAmerican, Nevada
Companies, North Carolina Commission, Northwestern, PNM-TNMP,
Progress Energy, Salt River, Snohomish, South Carolina Regulatory
Staff, Southern, Tacoma, and WAPA. Nevertheless, KCP&L, Nevada
Companies, and Progress Energy join with EPSA in calling for a more
formalized process for addressing base case and expansion plans.
    \193\ Georgia ITS consists of jointly-owned transmission
facilities, which are owned by the Southern subsidiary Georgia
Power, the Municipal Electric Authority of Georgia, the Georgia
Transmission Corporation--a cooperative utility--and Dalton
Utilities--a municipal system.
    \194\ E.g., Ameren, CAISO, Exelon, ISO New England, and
MidAmerican.
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    203. With regard to the imposition of reporting requirements, many
commenters argue that transmission providers already are required to
report joint planning activities.\195\ EEI, for example, contends that
joint planning activities under section 30.9 of the pro forma OATT
currently are required to be reported on each transmission provider's
OASIS. EEI argues that audits should not be required. Bonneville
contends that, at least in the Pacific Northwest, annual reporting and
audits are not needed. Bonneville states that transmission planning
staffs already bear a heavy workload; for example, Bonneville's
planning staff must address many requests for transmission and
interconnection service, as well as conduct regional planning efforts
and comply with regional and national reliability initiatives.
Northwestern states that reporting requirements or audits are not
needed and would be burdensome to the transmission provider,
distracting it from performing its joint planning responsibilities.
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    \195\ E.g., Bonneville, EEI, KCP&L, PNM-TNMP, Salt River,
Tacoma, and WAPA.
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Current pro forma OATT Planning Responsibilities
    204. Order No. 888 and the pro forma OATT require that transmission
providers plan and upgrade their transmission systems to provide
comparable open access transmission service for their transmission
customers. For example, with regard to network service, section 28.2 of
the pro forma OATT provides that the transmission provider ``will plan,
construct, operate and maintain its Transmission System in accordance
with Good Utility Practice in order to provide the Network Customer
with Network Integration Transmission Service over the Transmission
Provider's Transmission System.'' Section 28.2 also provides that the
Transmission Provider shall, consistent with Good Utility Practice,
``endeavor to construct and place into service sufficient transfer
capability to deliver the Network Customer's Network Resources to serve
its Network Load on a basis comparable to the Transmission Provider's
delivery of its own generating and purchased resources to its Native
Load Customers.''
    205. The pro forma OATT also requires that new facilities be
constructed to meet the service requests of long-term firm point-to-
point customers. Section 13.5 of the pro forma OATT requires the
transmission provider to consider redispatch of the system to relieve
any constraints that are inhibiting a transmission customer's point-to-
point service if it is economical to do so; but if redispatch is not
economical, the transmission provider is obligated to expand or upgrade
its system. This expansion obligation on the part of the transmission
provider for point-to-point service is found in section 15.4 of the pro
forma OATT, which provides that when a transmission provider cannot
accommodate a point-to-point transaction because of insufficient
capability on its system, it will ``use due diligence to expand or
modify its Transmission System to provide the requested Firm
Transmission Service.'' Section 15.4 goes on to provide that ``the
Transmission Provider will conform to Good Utility Practice in
determining the need for new facilities and in the design and
construction of such facilities.'' Importantly, however, the
transmission provider's obligation to upgrade or expand its system to
provide point-to-point service as detailed in section 15.4 is
contingent on the transmission customer agreeing to compensate the
transmission provider for such costs pursuant to the terms of section
27 (providing for cost responsibility for upgrades and/or redispatch
``to the extent consistent with Commission policy''). Order No. 888
does not, however, require that transmission providers coordinate with
either their network or point-to-point customers in transmission
planning or otherwise publish the criteria, assumptions, or data
underlying their transmission plans.\196\
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    \196\ Certain transmission data is required to be provided
annually in the FERC Form 715 (e.g., Part 2--Power Flow Base Cases,
Part 3--Transmitting Utility Maps and Diagrams, Part 4--Transmission
Planning Reliability Criteria, Part 5--Transmission Planning
Assessment Practices, and Part 6--Evaluation of Transmission System
Performance). As discussed below, we do not believe that the FERC
Form 715 reporting requirements have satisfied the need for
transparency with regard to transmission planning.
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The Need for Reform
    206. As discussed more fully in Part III.C above, in the ten years
since Order No. 888 was issued, the Nation has witnessed a decline in
transmission investment relative to load growth. As a result,
transmission capacity per MW of peak demand has declined in every NERC
region, and it has been estimated that capital spending must increase
significantly to ensure system reliability and to accommodate wholesale
electric markets. Many have argued that inadequate expansion of the
transmission grid has contributed to the widespread transmission
constraints that plague most regions of the country, as reflected in
the limited amounts of ATC posted in many regions, increased frequency
of denied transmission services requests, and increasingly common
transmission service interruptions or curtailments, all of which make
it more difficult for transmission customers to transfer power. In
short, it has become clear that since Order No. 888 was issued, the
Nation's transmission grid has not been planned and developed
adequately and projections suggest that without reform this trend will
continue.
    207. The need for transmission planning reform also has been
recognized by the Consumer Energy Council of America (CECA), a public
interest energy policy organization with a 30-year history of bringing
stakeholders together to find solutions to contentious energy policy
issues. CECA launched its Transmission Infrastructure Forum in early
2004,\197\ which published its conclusions in January 2005 in a final
report titled ``Keeping the Power Flowing: Ensuring a Strong
Transmission System to Support Consumer Needs for Cost-Effectiveness,
Security and Reliability'' (CECA Report).\198\ Among other things, the
CECA Report concludes that regional transmission planning with consumer
input early in the process is needed to ensure the development of a
robust transmission system capable of meeting consumer needs reliably
and at

reasonable cost over time. The CECA Report stresses that regional
transmission planning must address inter-regional coordination, the
need for both reliability and economic upgrades to the system, as well
as critical infrastructure to support national security and
environmental concerns.\199\
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    \197\ The CECA Transmission Infrastructure Forum included
representatives from such diverse constituencies as investor-owned
utilities, rural electric cooperatives, municipal power systems,
federal power systems, independent power producers, equipment
manufacturers, the U.S. Congress, the Commission, the U.S.
Department of Energy, state legislatures, state public utility
commissions, state energy offices and consumer advocates, consumer
and environmental organizations, independent consultants, and
academic institutions.
    \198\ Available at http://www.cecarf.org/Publications/PublicationsAllDate.html
.