[Federal Register: July 8, 2008 (Volume 73, Number 131)]
[Rules and Regulations]
[Page 39091-39156]
[DOCID:fr08jy08-22]

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Part II

Department of Energy

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Federal Energy Regulatory Commission

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18 CFR Part 37

Preventing Undue Discrimination and Preference in Transmission Service;
Final Rule

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 37

[Docket Nos. RM05-17-003 and RM05-25-003; Order No. 890-B]

Preventing Undue Discrimination and Preference in Transmission
Service

Issued June 23, 2008.
AGENCY: Federal Energy Regulatory Commission.

ACTION: Order on rehearing and clarification.

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SUMMARY: The Federal Energy Regulatory Commission affirms its basic
determinations in Order Nos. 890 and 890-A, granting rehearing and
clarification regarding certain revisions to its regulations and the
pro forma open-access transmission tariff, or OATT, adopted in Order
Nos. 888 and 889 to ensure that transmission services are provided on a
basis that is just, reasonable, and not unduly discriminatory. The
reforms affirmed in this order are designed to: Strengthen the pro
forma OATT to ensure that it achieves its original purpose of remedying
undue discrimination; provide greater specificity to reduce
opportunities for undue discrimination and facilitate the Commission's
enforcement; and increase transparency in the rules applicable to
planning and use of the transmission system.

DATES: Effective Date: This rule will become effective September 8,
2008.

FOR FURTHER INFORMATION CONTACT:
W. Mason Emnett (Legal Information), Office of the General Counsel--
Energy Markets, Federal Energy Regulatory Commission, 888 First Street,
NE., Washington, DC 20426,<PHONE_NUMBER>.
Daniel Hedberg (Technical Information), Office of Energy Market
Regulation, Federal Energy Regulatory Commission, 888 First Street,
NE., Washington, DC 20426,<PHONE_NUMBER>.

SUPPLEMENTARY INFORMATION:

                            Table of Contents

                                                              Paragraph
                                                                Number

I. Introduction............................................            1
II. Reforms of the OATT....................................            7
    A. Consistency and Transparency of ATC Calculations....            7
        1. Consistency.....................................            8
        2. Transparency....................................           25
    B. Transmission Pricing................................           38
        1. Energy and Generation Imbalances................           38
        2. Credits for Network Customers...................           46
        3. Capacity Reassignment...........................           68
        4. Operational Penalties...........................           87
        5. ``Higher Of'' Pricing Policy....................          102
        6. Other Ancillary Services........................          109
    C. Non-Rate Terms and Conditions.......................          116
        1. Modifications to Long-Term Firm Point-to-Point            116
         Service...........................................
        2. Rollover Rights.................................          141
        3. Acquisition of Transmission Service.............          155
        4. Designation of Network Resources................          162
        5. Clarifications Related to Network Service.......          216
        6. OATT Definitions................................          220
III. Information Collection Statement......................          250
IV. Document Availability..................................          251
V. Effective Date and Congressional Notification...........          254
Appendix A: Petitioners' Acronyms
Appendix B: Pro Forma Open Access Transmission Tariff

Before Commissioners: Joseph T. Kelliher, Chairman; Suedeen G.
Kelly, Marc Spitzer, Philip D. Moeller, and Jon Wellinghoff.

Order on Rehearing and Clarification

I. Introduction

    1. On February 16, 2007, the Commission issued Order No. 890,\1\
addressing and remedying opportunities for undue discrimination under
the pro forma Open Access Transmission Tariff (OATT) adopted in Order
No. 888.\2\ The pro forma OATT was intended to foster greater
competition in wholesale power markets by reducing barriers to entry in
the provision of transmission service. In the ten years since Order No.
888, however, flaws in the pro forma OATT undermined its ability to
realize the core objective of remedying undue discrimination. The
Commission acted in Order No. 890 to correct these flaws by reforming
the terms and conditions of the pro forma OATT in several critical
areas, including the calculation of available transfer capability
(ATC), the planning of transmission facilities, and the conditions of
services offered by each transmission provider.
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    \1\ Preventing Undue Discrimination and Preference in
Transmission Service, Order No. 890, 72 FR 12266 (March 15, 2007),
FERC Stats. & Regs. ] 31,241 (2007) (Order No. 890), order on reh'g,
Order No. 890-A, 73 FR 2984 (Jan. 16, 2008), FERC Stats. & Regs. ]
31,261 (2007) (Order No. 890-A).
    \2\ Promoting Wholesale Competition Through Open Access Non-
discriminatory Transmission Services by Public Utilities; Recovery
of Stranded Costs by Public Utilities and Transmitting Utilities,
Order No. 888, 61 FR 21540 (May 10, 1996), FERC Stats. & Regs. ]
31,036 (1996), order on reh'g, Order No. 888-A, 62 FR 12274 (Mar.
14, 1997), FERC Stats. & Regs. ] 31,048 (1997), order on reh'g,
Order No. 888-B, 81 FERC ] 61,248 (1997), order on reh'g, Order No.
888-C, 82 FERC ] 61,046 (1998), aff'd in relevant part sub nom.
Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (D.C.
Cir. 2000) (TAPS v. FERC), aff'd sub nom. New York v. FERC, 535 U.S.
1 (2002).
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    2. In Order No. 890-A, the Commission largely affirmed the reforms
adopted in Order No. 890. The Commission noted that work was well
underway to develop consistent practices governing the calculation of
ATC in coordination with the North American Electric Reliability
Corporation (NERC) and the North American Energy Standards Board
(NAESB). When complete, the reliability standards developed through
NERC and the business practices developed

through NAESB will eliminate the broad discretion that transmission
providers have in calculating ATC, increasing nondiscriminatory access
to the grid and ensuring that customers are treated fairly in seeking
alternative power supplies.
    3. The Commission also noted the substantial resources that
transmission providers have dedicated to the development of
transmission planning processes in response to Order No. 890.
Transmission planning is critical because it is the means by which
customers consider and access new sources of energy and have an
opportunity to explore the feasibility of non-transmission
alternatives. It is therefore vital for each transmission provider to
open its transmission planning process to customers, coordinate with
customers regarding future system plans, and share necessary planning
information with customers.
    4. In addition, transmission providers have implemented new service
options for long-term firm point-to-point customers and adopted
modifications to other services. Instead of denying a long-term request
for point-to-point service because as little as one hour of service is
unavailable, transmission providers now consider their ability to offer
a modified form of planning redispatch or a new conditional firm option
to accommodate the request. This increases opportunities to efficiently
utilize transmission by eliminating artificial barriers to use of the
grid. Charges for energy and generation imbalances also have been
standardized, including relaxed penalties for intermittent resources.
This standardization reduces the potential for undue discrimination,
increases transparency, and reduces confusion in the industry that
resulted from the prior lack of consistency.
    5. The Commission concluded that, taken together, these and other
reforms adopted in Order No. 890 will better enable the pro forma OATT
to achieve the core objective of remedying undue discrimination in the
provision of transmission service. The Commission therefore rejected
requests to eliminate, or substantially modify, the various reforms
adopted in Order No. 890. The Commission did, however, grant rehearing
and clarification regarding certain revisions to its regulations and
the pro forma OATT.
    Several petitioners have sought further rehearing and clarification
of the Commission's determinations in Order No. 890-A.\3\
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    \3\ A list of petitioners filing requests for rehearing and/or
clarification is provided in Appendix A.
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    6. The Commission largely affirms the determinations reached in
Order No. 890-A, granting limited rehearing and clarification to
address certain specific matters raised by petitioners. Revisions to
the pro forma OATT are required to implement several of these
determinations, although none disturb the fundamental nature of the
reforms adopted in Order No. 890. We therefore do not anticipate any
difficulty in their implementation or disruption in on-going compliance
efforts. We direct transmission providers that have not been approved
as RTOs or ISOs, and whose facilities are not in the footprint of an
RTO or ISO, to submit a Federal Power Act (FPA) section 206 filing that
contains the revised non-rate terms and conditions of the pro forma
OATT stated in Appendix B within 60 days of publication of this order
in the Federal Register. We direct RTO and ISO transmission providers,
transmission providers whose facilities are in the footprint of an RTO
or ISO, and WSPP to submit an FPA section 206 filing that contains the
revised non-rate terms and conditions of the pro forma OATT as stated
in Appendix B within 90 days of publication of this order in the
Federal Register.

II. Reforms of the OATT

A. Consistency and Transparency of ATC Calculations

    7. In Order No. 890-A, the Commission affirmed its conclusion in
Order No. 890 that the lack of consistency and transparency in the
methodology for calculating ATC creates the potential for undue
discrimination in the provision of open access transmission service. To
remedy this lack of consistency and transparency, the Commission
directed public utilities, working through the NERC reliability
standards and NAESB business practices development processes, to
produce workable solutions to implement ATC-related reforms adopted by
the Commission. A number of petitioners seek rehearing and/or
clarification regarding the Commission's ATC-related determinations in
Order No. 890-A, which we address below.
1. Consistency
a. Necessary Degree of and Process To Achieve Consistency
    8. The Commission affirmed the decision in Order No. 890 to require
consistency of all ATC components \4\ and certain definitions, data
inputs, data exchange, and modeling assumptions in order to reduce the
potential for undue discrimination in the provision of transmission
service. In response to petitioner requests, the Commission clarified
that adjacent transmission providers must coordinate and exchange data
and assumptions to achieve consistent ATC values on either side of a
single interface, regardless of whether they use the same or different
ATC methodologies. The Commission also reiterated that its regulations
require the posting of ATC values associated with a particular path,
not available flowgate capacity (AFC) values associated with a
flowgate. The Commission clarified, however, that a transmission
provider is free to post both ATC and AFC values. The Commission
further clarified that transmission-owning utilities in an RTO region
can request waiver of the requirement to convert AFC calculations into
ATC for posting purposes in the event the RTO has been granted such a
waiver.
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    \4\ The ATC components are total transfer capability (TTC),
existing transmission commitments (ETC), capacity benefit margin
(CBM), and transmission reserve margin (TRM).
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Requests for Rehearing and Clarification
    9. Duke, EEI, and E.ON U.S. object to the requirement that ATC
values be consistent on either side of an interface and suggest
alternatively that transmission providers be required to achieve
consistent TTC values on either side of the interface. Duke contends
that achieving consistency in TTC values will not necessarily result in
consistent ATC values. EEI agrees, arguing that ATC will be identical
on both sides of an interface only in the unlikely event that the
transmission providers each simultaneously receive and process
corresponding transmission requests and schedules for the same type of
product. EEI contends that transmission providers therefore will have
to expend substantial effort and resources to constantly monitor and
investigate differences in ATC values, the burden of which EEI argues
outweighs any benefit realized.
    10. Joined by E.ON U.S., Southern suggests that the Commission
clarify that ``consistent ATC values'' does not mean that ATC or TTC
values on either side of an interface must be identical. Southern
argues that interpreting ``consistent'' to mean ``identical'' would be
contrary to reliable planning and not reasonably achievable. Southern
contends that there are a number of reasons why adjacent transmission

providers may have varying ATC and TTC values on an interface,
including partial path transmission service, CBM and TRM, and the
impacts of multiple interfaces.
    11. EEI and E.ON U.S. also request the Commission clarify that the
process of achieving consistency of TTC values should occur through the
ongoing NERC and NAESB processes. They argue that the Commission in
Order No. 890 only required the consistency of components, definitions,
data and assumptions with respect to ATC and its components, including
TTC. They contend that the Commission did not require consistency in
ATC values or provide for a means to reconcile differences in ATC
calculations performed by multiple transmission providers. EEI and E.ON
U.S. suggest that it may take additional time for NERC and NAESB to
develop standards and business practices to achieve consistency in TTC
values or reconcile differences between ATC values at common
interfaces. Duke requests confirmation that compliance with the NERC
and NAESB methodologies regarding TTC and related calculations, once
they have been adopted and implemented, is sufficient to comply with
the consistency requirement imposed in Order No. 890-A.
    12. Entergy requests the Commission to clarify that Order No. 890-A
was not intended to reverse the Commission's prior determination that
Entergy and other transmission providers can rely on the scenario
analyzer to satisfy the ATC posting requirements in part 37 of the
Commission's regulations.\5\ Although Entergy uses an AFC methodology,
it posts ATC values on a path-specific basis by providing transmission
customers a scenario analyzer tool that allows them to instantaneously
evaluate transfer capability on a source-to-sink basis. Entergy states
that its scenario analyzer is also relied on by other transmission
providers, such as the Southwest Power Pool, Inc. and the Midwest
Independent Transmission System Operator, Inc. Entergy states that the
scenario analyzer will notify the customer the proposed request could
be approved if sufficient AFC exists.
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    \5\ Citing Entergy Servs., Inc., 106 FERC ] 61,115 (2004); 18
CFR 37.6(b)(2)(i) (2007).
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    13. Entergy notes that the Commission has previously concluded that
``Entergy's AFC methodology meets the established minimum posting
requirements for transmission capability set forth in Order No. 889,''
\6\ which Entergy argues were not changed in Order Nos. 890 or 890-A.
If the Commission intended in Order No. 890-A to modify the
requirements for posting ATC, or reverse its determination that the
scenario analyzer complies with the posting requirements, Entergy
requests clarification regarding what specific actions are required of
transmission providers that rely on the AFC process. Entergy also asks
that those transmission providers be allowed to continue using the
scenario analyzer until those measures are in place. Entergy states
that the sole purpose of the scenario analyzer has been to comply with
the Commission's posting requirements and that transmission providers
should not be required to maintain two different and duplicative
systems for meeting those requirements.
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    \6\ See Entergy Servs., Inc., 106 FERC ] 61,115 at P 50.
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    14. E.ON U.S. requests clarification that all transmission-owning
utilities within an RTO region can request waiver of the requirement to
convert AFC calculations into ATC for posting purposes in the event the
RTO has been granted such a waiver, and not just transmission-owning
utilities that are members of the RTO. E.ON U.S. states that many of
its neighboring systems utilize AFC instead of ATC, requiring it to
calculate AFC in order to transact with the adjacent RTO members, to
alleviate seams issues with these neighboring systems, and increase
transparency for across the border transactions. E.ON U.S. contends
that AFC calculations are much more accurate means to determine if
capacity is available on a flowgate than are ATC calculations. If the
Commission declines to grant the requested clarification, E.ON U.S.
seeks rehearing on the grounds that the Commission is creating new
seams where they do not currently exist by requiring transmission
capacity to be calculated differently on both sides of the border for
such transactions.
Commission Determination
    15. The Commission affirms the clarification provided in Order No.
890-A that adjacent transmission providers must coordinate and exchange
data and assumptions to achieve consistent ATC values on either side of
a single interface.\7\ We disagree with petitioners arguing that
``consistent'' ATC values should not be interpreted as identical. We
recognize that factors such as timing of reservation requests,
acceptances, and confirmations, and multiple interfaces between and
among transmission providers, can make it difficult to achieve
coincidental, identical postings of ATC values on both sides of an
interface. However, as the Commission explained in Order No. 890, if
all of the ATC components and certain data inputs and assumptions are
consistent, the ATC calculation methodologies being finalized by NERC
through the reliability standards development process should produce
predictable and sufficiently accurate, consistent, equivalent, and
replicable results.\8\ We therefore disagree that the directive to
coordinate and exchange data and assumptions to achieve consistent ATC
values on either side of an interface was newly imposed in Order No.
890-A. The Commission simply clarified that the requirement stated in
Order No. 890 applies equally to calculations of ATC on either side of
an interface.
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    \7\ See Order No. 890-A at P 52.
    \8\ See Order No. 890 at P 210.
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    16. Public utilities have already been directed to work through the
NERC and NAESB processes to achieve such consistency in ATC and TTC
values. In response to Duke, the Commission will address whether the
resulting reliability standards and business practices adequately
satisfy this consistency requirement on review of those reliability
standards and business practices. We note that public utilities were
recently granted an extension of time to finalize their work through
the NERC and NAESB processes. In Order No. 890, the Commission directed
each transmission provider to file a revised Attachment C to its OATT
to incorporate any changes associated with the revised reliability
standards and business practices within 60 days of completion of the
NERC and NAESB processes. We clarify that these revised Attachment C
filings are due 60 days after the date on which the relevant
reliability standards or business practices takes effect, not their
submission for Commission review.
    17. We grant the clarification requested by Entergy regarding the
Commission's February 11, 2004 determination that Entergy's AFC
methodology meets the minimum posting requirements for transmission
capability set forth in Order No. 889.\9\ The Commission did not amend
in Order Nos. 890 or 890-A the obligation for transmission providers to
post ATC values associated with a particular path instead of AFC values
associated with a flowgate.\10\ Prior determinations by the Commission
that a particular practice satisfies that obligation, or waiving that

obligation altogether, therefore remain intact.\11\
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    \9\ See Entergy Servs., Inc., 106 FERC ] 61,115 at P 50.
    \10\ See 18 CFR 37.6(b)(1)(i); see also Order No. 890 at P 211;
Order No. 890-A at P 51.
    \11\ See Order No. 890-A at P 36.
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    18. We disagree with E.ON U.S. that non-member transmission-owning
utilities within an RTO region are similarly situated to member
transmission-owning utilities, which the Commission noted in Order No.
890-A may request waiver of the requirement to convert AFC calculations
into ATC for posting purposes in the event the RTO has been granted
such a waiver. RTO members that have retained control over certain
transmission facilities operate those transmission facilities in
coordination with the RTO. In comparison, non-RTO members provide
transmission service independently and, therefore, for purposes of ATC
calculation are similar to a transmission provider outside the RTO
region. Nevertheless, we reiterate that a transmission provider is free
to post both ATC and AFC values if it believes such postings provide
additional transparency.\12\
b. ATC Components--CBM and TRM
    19. In Order No. 890-A, the Commission affirmed the decision in
Order No. 890 to require public utilities, working through NERC and
NAESB, to develop clear standards and business practices for how the
CBM value is determined, allocated across transmission paths and
flowgates, and used. The Commission also affirmed the requirement that
transmission providers design their transmission charges so that the
class of customers not benefiting from the CBM set-aside, i.e., point-
to-point customers, does not pay a transmission charge that includes
the cost of the CBM set-aside. The Commission explained that only
network customers and the transmission provider on behalf of its native
load may request that transmission capacity be set aside as CBM and,
therefore, only those users of the system should bear its costs. The
Commission also rejected requests to use CBM for reserve-sharing
arrangements, reiterating that TRM is the appropriate category for
reserve-sharing.
Requests for Rehearing and Clarification
    20. Southern requests rehearing of the Commission's statement that
non-firm point-to-point transmission customers only receive an indirect
benefit from CBM. Southern contends that under normal conditions
without generation deficiencies, non-firm point-to-point customers may
use CBM set-aside capacity. Southern states that it has not called upon
CBM to meet a generation deficit emergency in six years, resulting in
that capacity consistently being made available to non-firm customers.
Southern argues that non-firm customers therefore directly benefit from
CBM and should bear transmission charges that include the cost of the
capacity they are actually utilizing. If the Commission does not wish
to make a generic determination, Southern asks the Commission to
clarify that the issue of whether non-firm customers benefit from CBM
will be addressed on a case-by-case basis.
    21. TDU Systems request clarification of the Commission's statement
in Order No. 890-A that TRM is the appropriate category for reserve
sharing arrangements. TDU Systems request confirmation that, if a
transmission provider is using another form of set-aside for reserve
sharing purposes, such as CBM, the transmission providers' customers
are entitled to comparable use of the form of set-aside. TDU Systems
argue that comparability cannot be achieved where the transmission
provider does not offer use of transmission capacity set-asides to LSE
customers comparable to the use that the transmission provider allows
itself.
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    \12\ See Order No. 890-A at P 51.
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Commission Determination
    22. The Commission affirms the requirement adopted in Order No.
890, and affirmed in Order No. 890-A, that transmission providers
design their transmission charges so that the class of customers not
benefiting from the CBM set-aside, i.e., point-to-point customers, does
not pay a transmission charge that includes the cost of the CBM set-
aside.\13\ We disagree with Southern that non-firm customers benefit
directly from the CBM set-aside. The Commission acknowledged in Order
No. 890-A that capacity set aside for CBM may be made available to non-
firm customers when not otherwise in use.\14\ That benefit, however, is
indirect and inferior to the direct benefits enjoyed by those entities
that have the exclusive right to request the set-aside in the first
instance.
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    \13\ See Order No. 890 at P 263; Order No. 890-A at P 86.
    \14\ See Order No. 890-A at P 87.
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    23. The Commission acknowledged in Order No. 890-A that use of
capacity set aside for CBM by non-firm customers may result in revenues
that are credited to the transmission provider's cost of service, to
the benefit of point-to-point customers.\15\ The Commission stated its
expectation that transmission providers would address in rate design
filings any possibility for particular customers to receive an
inappropriate credit for non-firm use of capacity set aside for CBM.
Further clarification is unnecessary.
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    \15\ Id.
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    24. With regard to reserve sharing arrangements, the Commission
clearly stated in Order No. 890-A that TRM is the appropriate category
for reserve sharing arrangements and that, in comparison, CBM is used
to meet generation reliability criteria in times of emergency
generation deficiencies.\16\ Therefore, transmission providers must use
TRM, not CBM, for reserve sharing arrangements and make ATC set aside
for that purpose available to all LSEs on a comparable basis for any
reserve sharing arrangements they may have.
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    \16\ Id. P 85.
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2. Transparency
    25. In Order No. 890-A, the Commission clarified that all data used
to calculate ATC and TTC for any constrained paths and any system
planning studies or specific network impact studies performed for
customers are to be made available on request, regardless of whether
the customer is non-affiliated or affiliated with the transmission
provider. The Commission also clarified that underlying load forecast
assumptions to be posted on OASIS should include economic and weather-
related assumptions. The Commission concluded that posting load
forecast and actual load data on a control area and LSE level does not
raise serious competitive implications. The Commission stated that it
would consider requests for exemption from this posting requirement on
a case-by-case basis if there is customer-specific information deemed
confidential by the affected customer that impedes the ability of the
transmission provider to post this data.\17\
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    \17\ Id. P 143.
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    26. The Commission further clarified that transmission providers
must make available, upon request and subject to appropriate
confidentiality protections and CEII requirements, certain modeling
data including load flow base cases and generation dispatch methodology
and, subject to additional reasonable and applicable generator
confidentiality limitations, production cost models (including
assumptions, settings, study results, input data, etc.). The Commission
declined to require transmission providers to post this information on
OASIS.
Requests for Rehearing and Clarification
    27. Duke seeks clarification of the requirement to post information
requested by an affiliate when that information is already available to
the

public. Duke suggests that only a notice that an affiliate requested a
publicly-available study needs to be posted, and not the actual study,
because the additional effort of posting the actual study would be
redundant, burdensome, and without purpose.
    28. Duke, EEI and Southern request rehearing to eliminate the
requirement to post the underlying assumptions used to develop load
forecasts on a daily basis, including economic and weather-related
assumptions. They claim that the requirement is a substantial
modification of regulations adopted in Order No. 890, is unduly
burdensome, and may cause transmission providers to violate their
contractual obligations by releasing proprietary assumptions and
forecasts obtained from forecasting service providers. Southern also
complains that it is unclear what is meant by ``economic assumptions''
and any requirement to provide daily updates of such assumptions would
be unduly burdensome given the amount of effort required and negligible
benefit that customers might gain from the information.
    29. Duke argues that the Commission's expansion of posting
requirements to include load forecast assumptions daily is an entirely
new requirement for which notice and comment has not been provided.
Duke contends that Constellation's request for rehearing of Order No.
890 mentioning load forecast assumptions was inadequate to provide
notice because Constellation did not request that load forecast
assumptions be posted on a daily basis or that load forecast
assumptions unrelated to ATC calculations be posted.
    30. If the Commission declines to eliminate this posting
requirement, Duke suggests that it be amended to require a one-time
(i.e., not daily) posting of a list of factors that go into the peak
load forecast, such as day of the week, a day's status as holiday or
non-holiday, temperature, dew point, precipitation forecast, etc. If
the Commission continues to require the daily posting of information,
Duke seeks clarification regarding the granularity of such information
given that it could vary widely over a control area. Duke questions
whether, for example, PJM would have to post weather forecasts for each
of its subregions. Until the Commission grants the requested
clarification, Duke argues that the posting requirement should be
waived or transmission providers should be permitted to satisfy the
requirement by reference to commercial/government weather websites.
    31. Southern seeks clarification of the requirement to make
available, on request, the modeling data identified in paragraph 148 of
Order No. 890-A. Southern states that it does not use all of the
specified modeling data to calculate ATC, TTC, CBM and/or TRM. In
particular, Southern argues that neither production cost models nor
special protection systems and operation guides are used in its ATC
calculations and that production cost models in particular are not even
maintained by its transmission function given its highly sensitive
nature. Southern asks the Commission to clarify that transmission
providers are required to provide only the specified modeling data
actually used in performing those calculations and that a transmission
provider is not required to manufacture and/or produce the data in the
event it does not use a particular input in its ATC calculations.
    32. Duke also argues that production cost models and generation
dispatch methodologies typically contain commercially sensitive or
proprietary information or information that should not be released to
the public. Duke acknowledges that the Commission stated that
availability of production cost models would be subject to reasonable
and applicable generator confidentiality limitations,\18\ but argues
that still would allow employees or consultants of competing entities
to be provided access to sensitive data. Duke therefore asks the
Commission to confirm that reasonable and applicable generator
confidentiality limitations means that the proprietary/sensitive
information may be released only to transmission function personnel
that are restricted from further disclosure, including to their own
merchant functions. Duke also requests clarification that the
transmission provider's merchant/generation function and third-parties
are to be treated identically as to their right to classify which
information that they have given to a transmission provider is
proprietary/sensitive, in accordance with Commission policies.
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    \18\ Citing Order No. 890-A at P 148.
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Commission Determination
    33. The Commission clarifies in response to Duke that, when an
affiliate requests information that is already available to the public,
the transmission provider need only post a notice that an affiliate
requested the particular information, not the actual information. This
clarification applies, however, only to those instances in which the
actual information is already publicly available.
    34. We affirm the requirement that each transmission provider post
on a daily basis its load forecast, including underlying assumptions,
and actual daily peak load for the prior day.\19\ In the NOPR, the
Commission specifically raised the possibility of requiring
transmission providers to make available their underlying load forecast
assumptions for all ATC calculations.\20\ The Commission adopted that
proposal in Order No. 890, but failed to amend its regulations
accordingly.\21\ The Commission corrected that oversight in Order No.
890-A.\22\ We therefore disagree with Duke that transmission providers
were not on notice that posting of load forecast data and related
assumptions might be required.
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    \19\ 18 CFR 37.6(b)(3)(iv) (2007).
    \20\ See Preventing Undue Discrimination and Preference in
Transmission Services, Notice of Proposed Rulemaking, FERC Stats. &
Regs. ] 32,603, at P 194 (2006) (NOPR).
    \21\ See Order No. 890 at P 416.
    \22\ See Order No. 890-A at P 143.
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    35. We clarify, however, that the Commission intended for
transmission providers to post the underlying factors used to make load
forecasts that have a significant impact on calculations, such as
temperature forecasts, not all economic and other data that underlies
each and every daily load forecast. Transmission providers must post a
description of their load forecast method including how economic and
weather assumptions are used in load forecasting. The Commission's
intent is to increase transparency in the transmission provider's
process of forecasting, providing assurance to customers that loads are
consistently being forecast using methodologies which are not subject
to daily manipulation to favor affiliates.
    36. We also affirm the requirement to make available, upon request
and subject to appropriate confidentiality protections and CEII
requirements, certain modeling data including load flow base cases and
generation dispatch methodology and, subject to additional reasonable
and applicable generator confidentiality limitations, production cost
models (including assumptions, settings, study results, input data,
etc.).\23\ We clarify in response to Southern that a transmission
provider is not required under Order Nos. 890 or 890-A to manufacture
or otherwise make available modeling data that it does not use in its
ATC calculations. However, if the specified modeling data are used for
the calculation of ATC, or any of its components, they must be

made available as required in Order No. 890-A.
---------------------------------------------------------------------------

    \23\ See Order No. 890-A at P 148.
---------------------------------------------------------------------------

    37. We agree with Duke that production cost models and generation
dispatch methodologies may contain commercially sensitive or
proprietary information. Transmission providers are therefore permitted
to condition the release of such information on appropriate
confidentiality restrictions. With regard to production costs models,
reasonable applicable generator confidentiality limitations could
include, among other things, restrictions on the release of proprietary
and commercially sensitive information to those engaged in the
marketing, sale, or purchase of electric power at wholesale. We agree
that the transmission provider's merchant and/or generation personnel
and third-parties are to be treated identically as to their right to
classify proprietary or commercially sensitive information that they
provide to a transmission provider, as well as their right to receive
such data from the transmission provider.

B. Transmission Pricing

1. Energy and Generation Imbalances
a. Generator Imbalance Penalties
    38. In Order No. 890-A, the Commission affirmed the decision in
Order No. 890 to adopt standardized generator imbalance provisions in
Schedule 9 of the pro forma OATT. The Commission clarified that a
transmission provider only has to provide generator imbalance service
from its own resources to the extent that it is physically feasible to
do so (i.e., the transmission provider is able to manage the additional
potential imbalances without compromising reliability). Each
transmission provider may state on its OASIS the maximum amount of
generator imbalance service that it is able to offer from its resources
based on an analysis of the physical characteristics of its system.
Alternatively, a transmission provider may consider requests for
generator imbalance service on a case-by-case basis, performing as
necessary a system impact study to determine the precise amount of
additional generation it can accommodate and still reliably respond to
the imbalances that could occur.
    39. The Commission clarified that neither of these options relieves
the transmission provider of its obligation to provide generator
imbalance service if it is able to acquire additional resources to do
so. If it is not physically feasible for the transmission provider to
offer generator imbalance service using its own resources, either
because they do not exist or they are fully subscribed, the
transmission provider must attempt to procure alternatives to provide
the service, taking appropriate steps to offer an option that customers
can use to satisfy their obligation to acquire generator imbalance
service as a condition of taking transmission service. If no such
resources are available, the transmission provider must accept the use
of dynamic scheduling to the extent a transmission customer has
negotiated an appropriate arrangement with a neighboring control area.
Request for Clarification
    40. E.ON U.S. seeks clarification of the time frame within which
the transmission provider must post the availability of service (e.g.,
an hourly, 24-hour, or monthly interval). E.ON U.S. also asks the
Commission to clarify the time frame required for obtaining imbalance
service from other sources and the extent to which a transmission
provider is obligated to seek such resources. E.ON U.S. suggests that
this obligation could be interpreted as requiring only a single search
or a constant search for resources over a long period of time. E.ON
U.S. seeks further clarification regarding the point in the process
when the transmission provider must inform the generator that it must
arrange for dynamic scheduling because no other option is available.
Commission Determination
    41. The Commission affirms the decision in Order No. 890-A to allow
a transmission provider to post on its OASIS the maximum amount of
generator imbalance service it is able to offer without impairing
reliability.\24\ To the extent necessary, we clarify that a
transmission provider must post the availability of generator imbalance
service and seek imbalance service from other sources in a manner that
is reasonable in light of the transmission provider's operations and
the needs of its imbalance customers. What is reasonable for some
imbalance customers and transmission providers may be unreasonable for
others. We therefore decline to set a specific time frame within which
the transmission provider must post the availability of generator
imbalance service. For the same reason, we decline to set a generic
time frame for obtaining imbalance service from other sources in the
event it is not physically feasible to offer generator imbalance
service using the transmission provider's resources.
---------------------------------------------------------------------------

    \24\ Order No. 890-A at P 289.
---------------------------------------------------------------------------

    42. In the event that there are no additional resources available
to enable the transmission provider to meet its obligation to provide
generator imbalance service, the transmission provider must accept the
use of dynamic scheduling by a transmission customer.\25\ The
transmission provider cannot, however, require the use of dynamic
scheduling, since the customer may choose to make other alternative
comparable arrangements to self supply generator imbalance service. If
a customer chooses to use dynamic scheduling in this circumstance, it
is the option and the responsibility of the transmission customer to
seek out and appropriately negotiate dynamic scheduling with a
neighboring control area. The transmission provider is required to
accommodate the use of dynamic scheduling only to the extent the
transmission provider is unable to provide generator imbalance service
and the customer has negotiated appropriate arrangements with the
relevant control areas.
---------------------------------------------------------------------------

    \25\ Id. P 290.
---------------------------------------------------------------------------

b. Definition of Incremental Cost
    43. In Order No. 890-A, the Commission granted rehearing of its
decision to calculate incremental costs for the purpose of assessing
imbalance charges based on the last 10 MW dispatched to supply the
transmission provider's native load. The Commission determined that it
is more reasonable to base imbalance charges on the actual cost to
correct the imbalance, which may be different than the cost of serving
native load. Accordingly, the Commission modified the definition to
require transmission providers to use the cost of the last 10 MWs
dispatched for any purpose, i.e., to serve native load, correct
imbalances, or to make an off-system sale.
Requests for Rehearing and Clarification
    44. EEI and Southern argue that the Commission mistakenly used
``i.e.'' instead of ``e.g.'' when referring to the costs to be included
in the calculation of charges for energy imbalance service and
generator imbalance service. EEI contends that the specified purposes
exclude costs to serve other customers, such as on-system customers who
take partial requirements service from the transmission provider. EEI
asks the Commission to clarify that it meant to use ``e.g.'' to
indicate that the list of examples provided were non-exclusive.
Southern similarly requests that Schedules 4 and 9 of the pro forma
OATT be revised to use ``e.g.'' instead of ``i.e.''

Commission Determination
    45. The Commission grants rehearing of the definition of
incremental cost as described in the preamble of Order No. 890-A and in
Schedules 4 and 9 of the pro forma OATT. Those schedules define
incremental cost and decremental cost as ``the Transmission Provider's
actual average hourly cost of the last 10 MW dispatched for any
purpose.'' \26\ We agree that use of the term ``e.g.'' instead of
``i.e.'' when referring to the types of energy to be included in the
incremental cost calculation better reflects the Commission's intent to
include within that calculation the last 10 MW dispatched for any
purpose. We revise the pro forma OATT accordingly.\27\
---------------------------------------------------------------------------

    \26\ Schedules 4, 9 of the pro forma OATT.
    \27\ We note in response to EEI, however, that the existing
reference to native load in Schedules 4 and 9 already includes on-
system customers taking requirements service under section 1.23 of
the pro forma OATT.
---------------------------------------------------------------------------

2. Credits for Network Customers
    46. In Order No. 890-A, the Commission affirmed its decision in
Order No. 890 to sever the link in the pro forma OATT between joint
planning and credits for new facilities owned by network customers. As
the Commission explained in Order No. 890, the linkage between credits
and joint planning gave the transmission provider an incentive to deny
coordinated planning to avoid granting credits for customer-owned
facilities. The Commission concluded that any efficiencies that may be
lost by severing that link should be offset by the increased
efficiencies resulting from the coordinated planning reforms adopted in
Order No. 890, which the Commission noted will ensure that most, if not
all, transmission facilities are planned on a coordinated basis.
    47. The Commission similarly affirmed the decision to adopt a
revised test to determine whether a network customer is eligible to
receive credits for new facilities. Under the revised section 30.9 of
the pro forma OATT, customers are eligible for credits for those
facilities that are integrated with the operations of the transmission
provider's facilities; provided, that integration will be presumed for
customer-owned facilities that, if owned by the transmission provider,
would be eligible for inclusion in the transmission provider's annual
transmission revenue requirement as specified in Attachment H of the
pro forma OATT. The Commission clarified in Order No. 890 that this
revision did not alter the underlying integration standard. In order to
satisfy the integration standard, the customer must show that its new
facility is integrated with the transmission provider's system,
provides additional benefits to the transmission grid in terms of
capability and reliability, and can be relied on by the transmission
provider for the coordinated operation of the grid.\28\
---------------------------------------------------------------------------

    \28\ Order No. 890 at P 754, n. 436 (citing Southwest Power
Pool, Inc., 108 FERC ] 61,078 (2004), reh'g denied, 114 FERC ]
61,028 (2006)).
---------------------------------------------------------------------------

    48. The Commission explained in Order No. 890-A that adoption of
the presumption of credits in section 30.9 was necessary to ensure
comparability between network customers and transmission providers
serving load. To that end, the Commission clarified that the
presumption of integration is rebuttable as applied to both the
transmission provider and the network customer. A transmission provider
may challenge the presumption that the customer's facilities are
integrated by showing that the customer's facilities do not actually
meet the integration standard, notwithstanding the fact that they are
similar to facilities in the transmission provider's rate base.
Similarly, a customer could challenge the presumption that a
transmission provider's facilities are integrated by showing that the
facilities, for example, do not provide network benefits. As a result,
the Commission clarified that denial of credits for a network customer
no longer triggers a need for the transmission provider to demonstrate
that its own facilities satisfy the integration standard.
Requests for Clarification and Rehearing
    49. NRECA and TAPS ask the Commission to clarify whether it
intended to apply a single integration standard to both transmission
customer and transmission provider facilities and, if so, what standard
will apply. These petitioners contend that several passages in Order
No. 890-A suggest that the Commission will now apply a single
integration standard, no matter whose facilities are under
consideration. They note, for example, the Commission's statement in
paragraph 353 of Order No. 890-A that ``[a] transmission provider may
overcome the network customer's presumed integration by demonstrating,
with reference to its own facilities that meet the integration
standard, that the network customer's facilities do not meet the
standard.'' \29\ They point to another statement that it is
``appropriate for both the transmission provider and its customers to
be subject to the integration standard to the extent the presumption of
integration is overcome.'' \30\ These petitioners express concern,
however, regarding the Commission's statement that the integration
standard for credits under section 30.9 remains unchanged and that
precedents applying that standard will continue to apply. They argue
that those precedents establish and apply a significantly more
stringent test for integration of customer-owned facilities than for
facilities of the transmission provider.\31\
---------------------------------------------------------------------------

    \29\ Order No. 890-A at P 353.
    \30\ Id. P 354.
    \31\ Citing East Texas Elec. Coop., Inc. v. Central & South West
Services, Inc. 108 FERC ] 61,079 (2004), reh'g denied, 114 FERC ]
61,027 (2006) (ETEC); Northeast Tex. Elec. Coop., Inc., 108 FERC ]
61,108, at P 48 (2004), reh'g denied, 111 FERC ] 61,189 (2005)
(NTEC).
---------------------------------------------------------------------------

    50. TAPS suggests that the Commission's new policy for new
transmission facilities must mean one of three things. Its first and
preferred possibility is that, in assessing whether the new integration
presumption has been overcome, the Commission will apply a single
integration standard to both the transmission provider and the
transmission customer, i.e., the relaxed standard that has long applied
in determining whether a transmission provider's facilities should be
rolled into its rate base. Under a second possibility, a single
integration standard also would apply, but transmission providers would
be held to the same strict integration standard to which transmission
customers seeking section 30.9 credits have long been subject. As a
final interpretation, TAPS states that, to overcome the presumption
applicable to new transmission facilities, the Commission could
continue to apply two different tests: The more stringent one
applicable to customers seeking credits and the more relaxed one for
transmission providers to include facilities in rate base. TAPS notes,
however, that this would be inconsistent with Order No. 890-A's
repeated references to a single, comparable integration standard that
applies to both customer and transmission providers.
    51. East Texas Cooperatives agree that the case law establishes a
different and harder test for integration of customer-owned facilities.
East Texas Cooperatives state that, under that precedent, a
transmission provider needs only to run the load flow study used in
ETEC to challenge credits for a customer-owned facility. East Texas
Cooperatives argue that this load flow study cannot be satisfied by any
transmission facilities, since it takes out both customer facilities
and load and asks if the grid can still run reliably. In comparison,
East Texas Cooperatives

contend that the cost of transmission provider facilities would
continue to be presumptively rolled in subject to challenge unless a
party can show that those facilities are so isolated from the grid that
they are and will likely remain non-integrated and thus provide no
benefit to the system.
    52. East Texas Cooperatives therefore argue that the Commission's
statement in Order No. 890-A regarding the continued applicability of
integration precedent mandates discrimination in favor of transmission
provider facilities in violation of the FPA. They contend that
eligibility for rolled-in rate treatment of the same facilities would
vary solely as a result of their ownership, since customer-owned
facilities that are found not to be integrated under a load flow
integration test would become integrated if purchased by the
transmission provider, which is subject to a more relaxed application
of the integration standard. East Texas Cooperatives suggest that the
Commission justified its application of a more difficult test to
network customers on a presumption that the customer-owned facilities
are less integrated than transmission provider facilities. Joined by
NRECA and TAPS, East Texas Cooperatives argue that customer-owned
facilities are built to serve customer loads just as transmission
provider facilities are built to serve transmission provider loads.
These petitioners contend that there is no basis in the record for
presuming that transmission provider facilities are more integrated
than customer facilities.
    53. FMPA, NRECA and TDU Systems contend that contradictory
statements in Order No. 890-A could be read to apply the more stringent
integration standard to customer-owned facilities and a more relaxed
integration standard for transmission provider facilities.\32\ In
particular, these petitioners question what standard the Commission was
referring to in paragraph 353 of Order No. 890-A when it stated that
the transmission provider may overcome the network customer's presumed
integration by demonstrating, with reference to its own facilities that
meet the integration standard, that the network customer's new
facilities do not meet the standard, i.e., the ``integration standard''
or the ``similar in purpose and design'' standard. NRECA and TDU
Systems argue that the appropriate standard to apply when both claiming
and rebutting the presumption of integration is whether the customer's
facilities are similar in design and purpose to those of the
transmission provider that are in rates.
---------------------------------------------------------------------------

    \32\ Citing Order No. 890-A at P 351-52.
---------------------------------------------------------------------------

    54. Florida Power also requests clarification of language in
paragraph 353 of Order No. 890-A. Florida Power asks the Commission to
confirm that this statement applies only to determine whether the
customer is entitled to the presumption in the first place, not to
rebut of the presumption once established, and that the standard to
which the Commission was referring is whether the customer-owned
facilities are similar in design and purpose to facilities owned by the
transmission provider that are included in rates. Florida Power also
asks the Commission to confirm that the transmission provider could
oppose a customer's initial attempt to establish a presumption of
credits by showing, by reference to the transmission provider's own
facilities that meet the integration standard, that the customer-owned
facilities are not similar in design and purpose to facilities owned by
the transmission provider that are included in rates.
    55. With regard to rebutting the presumption once established,
Florida Power requests confirmation that the transmission provider can
overcome the presumption by showing that the customer-owned facilities
do not meet the integration standard, i.e., that it does not need the
network customer's facility to serve the network customer, the
transmission provider's other transmission customers, or the
transmission provider's retail customers.\33\ Florida Power contends
that it would not be just and reasonable, or consistent with the cost
causation principle, to shift the cost of customer-owned facilities if
those facilities do not benefit the transmission provider's system.
---------------------------------------------------------------------------

    \33\ Citing Southern California Edison Co., 108 FERC ] 61,085,
at P 9 n.11 (2004); Southwest Power Pool, Inc., 108 FERC ] 61,078,
at P 18 n.7 (2004), reh'g denied, 114 FERC ] 61,028 (2006); ETEC,
108 FERC ] 61,079, at P 26 n.11; Northern States Power Co., 87 FERC
] 61,121 at 61,488 (1999).
---------------------------------------------------------------------------

    56. E.ON U.S. argues that the rebuttable presumption of integration
should apply only to customer-owned facilities that are planned through
the Attachment K or similar process. If the Commission's expectation
that most, if not all, transmission upgrades eligible for credits will
be planned in the Attachment K process is true, E.ON U.S. suggests that
the rebuttable presumption of integration most reasonably applies only
to facilities planned through that process.\34\ E.ON U.S. contends that
linking credits for customer-owned facilities to the Attachment K
planning process would allow the transmission provider an opportunity
to coordinate with customers on facilities, while preventing any
opportunities for undue discrimination given the non-discretionary
nature of the planning obligation. E.ON U.S. argues that failure to
plan facilities through the Attachment K or similar process should
trigger a presumption against receiving credits for such facilities.
---------------------------------------------------------------------------

    \34\ Citing Order No. 890-A at P 426.
---------------------------------------------------------------------------

    57. Several petitioners request rehearing of the Commission's
determination that denial of credits for a network customer would no
longer trigger a need for the transmission provider to demonstrate that
its own facilities satisfy the integration standard. East Texas
Cooperatives contend that this decision improperly reverses the
approach adopted in FP&L \35\ and prohibits a network customer from
challenging the rolled-in rate treatment of transmission provider
facilities even when the customer's own facilities are found ineligible
for credits. TAPS contends that reversing this policy is inconsistent
with notions of comparability unless the Commission clarifies, as
requested above, that the relaxed integration standard applies to both
network customers and transmission providers. If a network customer's
facilities are disqualified from eligibility for credits due to
application of a more stringent integration standard, TAPS and TDU
Systems argue that comparability requires the removal of the
transmission provider's similar facilities from rates. NRECA agrees,
arguing that the transmission provider must be required to remove its
facilities from rates if customer-owned facilities that are similar in
design and purpose to those transmission provider facilities are found
ineligible for credits under the integration standard.
---------------------------------------------------------------------------

    \35\ Florida Mun. Power Agency v. Florida Power and Light Co.,
74 FERC ] 61,006, at 61,010 (1996), reh'g denied, 96 FERC ] 61,130,
at 61,544-45 (2001), aff'd sub nom. Florida Mun. Power Agency v.
FERC, 315 F.3d 362 (D.C. Cir. 2003) (FP&L).
---------------------------------------------------------------------------

    58. TAPS and FMPA ask the Commission to clarify that removal of the
trigger applies only to denial of credit for new facilities to which
the new presumption of integration applies. TAPS and FMPA point to
language in paragraph 352 of Order No. 890-A providing that ``the
denial of credits for a network customer no longer triggers a need for
the transmission provider to demonstrate that its own facilities
satisfy the integration standard.'' Both FMPA and TAPS interpret this
language as applying to new facilities only. TAPS contends that the
Commission does not and cannot offer any justification for

dispensing with the trigger in cases involving requests for credits for
existing facilities, in which the presumption of integration adopted in
Order No. 890 does not apply. TAPS is concerned that transmission
providers will seek to remove the trigger for existing facilities,
relying, inter alia, on the more general reference in Order No. 890-A
to elimination of trigger.
    59. Finally, FMPA seeks clarification on how the Commission's
determinations on transmission credits will affect pending cases. FMPA
asks the Commission to confirm that Order No. 890-A will not be applied
to deny or weaken the comparability requirement for facilities at issue
in Docket No. ER93-465-000, et al. FMPA also asks the Commission to
clarify that the transmission credit policy articulated in Order No.
890 and Order No. 890-A will not preclude FMPA's ability to obtain full
relief if the D.C. Circuit remands the Commission's decisions at issue
in Fla. Mun. Power Agency v. FERC regarding charges for transmission
that a network customer is physically unable to use.\36\
---------------------------------------------------------------------------

    \36\ No. 06-1285 (D.C. Cir. filed July 26, 2006).
---------------------------------------------------------------------------

Commission Determination
    60. The Commission affirms the decision in Order Nos. 890 and 890-A
to revise the test for determining whether a network customer is
eligible to receive credits for new facilities. Under the revised
section 30.9 of the pro forma OATT, a network customer is eligible for
credits if it demonstrates that its facilities are integrated with the
operations of the transmission provider's facilities, provided that
integration will be presumed for new customer-owned facilities that, if
owned by the transmission provider, would be eligible for inclusion in
the transmission provider's annual transmission revenue requirement as
specified in Attachment H of the pro forma OATT. As the Commission
explained in Order No. 890-A, the adoption of this presumption ensures
comparability between network customers and transmission providers
serving native load given that transmission providers are now obligated
to plan their systems on an open and coordinated basis.\37\
---------------------------------------------------------------------------

    \37\ See Order No. 890-A at P 350.
---------------------------------------------------------------------------

    61. Several petitioners question how this revised test is
consistent with the Commission's statements that the integration
standard applicable to new facilities remains unchanged and that
Commission precedent regarding application of that standard will
continue to apply.\38\ As these petitioners note, the integration
standard has historically been applied differently to network customers
and transmission providers.\39\ Transmission facilities owned by the
transmission provider enjoyed a presumption of rolled-in rate treatment
so long as any degree of integration was shown, while network customers
were required to demonstrate affirmatively that their facilities were
relied upon by the transmission provider to provide service to its
customers.\40\ The Commission therefore described the test for
integration for network customer facilities as being more stringent
than the test applied to transmission provider facilities.\41\ The
application of the integration standard was, in fact, more stringent as
applied to network customers because they did not enjoy the benefit of
presumed integration, as did the transmission provider. The underlying
integration standard, however, has been and continues to be the same
for all transmission facilities. Only those facilities that are, in
fact, integrated with the transmission grid and used by the
transmission provider to serve customers should be subject to rolled-in
rate treatment. It is in this sense that the precedent continues to
apply, providing guidance regarding the treatment of facilities that
benefit from the presumption of integration and those that do not.
---------------------------------------------------------------------------

    \38\ See Order No. 890-A at P 349.
    \39\ Compare Utah Power & Light Co., 27 FERC ] 61,258, at
61,485-87 (1984), reh'g denied, 28 FERC ] 61,088, at 61,165 (1984)
(citing Utah Power & Light Co., Opinion No. 113, 14 FERC ] 61,112,
reh'g denied, 15 FERC ] 61,076 (1981)) with ETEC, 114 FERC ] 61,027
at P 42.
    \40\ NTEC, 111 FERC ] 61,189 at P 17.
    \41\ Id. P 15.
---------------------------------------------------------------------------

    62. The presumption of integration enjoyed by the transmission
provider has never been absolute. Customers have always been able to
challenge the inclusion of certain transmission provider facilities by
showing that the facilities did not actually provide a systemwide
benefit to the transmission grid.\42\ In most instances, however, this
has not been the case given that the transmission provider generally
plans, constructs and owns its facilities, from the very beginning, to
meet delivery obligations, which justifies the presumption of
integration.\43\ In the event the transmission provider denied credits
to a network customer, however, the transmission provider lost the
benefit of the presumption and the same integration standard applied to
customer-owned facilities was applied to the transmission provider's
facilities.\44\ This again demonstrates that the same underlying
integration standard has applied to all facilities, regardless of
ownership, notwithstanding the presumed integration generally enjoyed
by the transmission provider.
---------------------------------------------------------------------------

    \42\ See Idaho Power Co., 3 FERC ] 61,108 (1978), reh'g denied,
5 FERC ] 61,009 (1978); Minnesota Power & Light Co., 16 FERC ]
63,012 (1981), aff'd 21 FERC ] 61,233 (1982).
    \43\ See Niagara Mohawk Power Corp., 42 FERC ] 61,143, at 61,531
(1988); Otter Tail Power Co., 12 FERC ] 61,169, at 61,420 (1980).
    \44\ See Florida Power & Light Co., 105 FERC ] 61,287, at P 16
(2003).
---------------------------------------------------------------------------

    63. In light of the planning-related reforms implemented in Order
No. 890, the Commission determined it is now appropriate to grant the
same presumption of integration to new customer-owned facilities that
are similar in scope and design to those transmission provider
facilities that are in rates. Implementation of planning-related
reforms will now ensure that most, if not all, transmission facilities
are planned on a coordinated basis.\45\ However, only those new
customer-owned facilities that are similar in design and purpose to the
transmission provider's facilities that are in rates will be eligible
for the presumption of rolled-in rate treatment. Other customer-owned
facilities will be eligible for credits only if the network customer is
able to make an affirmative showing that the facilities satisfy the
integration standard, i.e., that the facilities are nonetheless
integrated notwithstanding their ineligibility for the presumption of
integration.\46\
---------------------------------------------------------------------------

    \45\ See Order No. 890 at P 736; Order No. 890-A at P 337.
    \46\ See, e.g., Ne. Tex. Elec. Coop., Inc., 111 FERC ] 61,189 at
P 16.
---------------------------------------------------------------------------

    64. To be clear, if the transmission provider disagrees that the
customer-owned facilities are similar in design and purpose to its own
facilities, it may challenge the threshold application of the
presumption with a comparative analysis of its facilities and those for
which credits are claimed. Neither the transmission provider nor the
network customer need analyze complete satisfaction of the integration
standard in order to determine whether, as a threshold matter, the
presumption of integration applies. Assuming that the network customer
prevails in its claim for presumed integration, then the network
customer will enjoy the same rolled-in rate treatment enjoyed by the
transmission provider for its similar facilities. As the Commission
explained in Order No. 890, this is appropriate to ensure comparability
between the transmission provider and network customer now that all
transmission facilities will be planned pursuant to an open and
coordinated process.\47\
---------------------------------------------------------------------------

    \47\ Order No. 890 at P 435.

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

    65. The transmission provider may nevertheless overcome the
presumption of integration by demonstrating, with reference to its own
facilities that meet the integration standard, that the customer-owned
facilities are not, in fact, integrated and do not provide benefits to
the system. The same is true of transmission provider facilities
previously presumed to be integrated. In either case, the challenging
party will bear the burden in overcoming the presumption of integration
and rolled-in rate treatment. It is for this reason that it would no
longer be appropriate to remove the presumption of integration enjoyed
by the transmission provider, i.e., apply the more strict integration
standard, upon denial of credits to a network customer. In the past,
only the transmission provider enjoyed the presumption of integration,
which justified elimination of the presumption in the event credits
were denied to a network customer. Both transmission providers and
network customers now enjoy the benefits of presumed integration, and
both may challenge application of the presumption to each other's
facilities. We continue to believe that this will ensure that all
similar facilities that are, in fact, not part of the integrated
network that serves all customers are excluded from rates.\48\ We
acknowledge that this approach departs from the approach adopted in
FP&L.\49\ Our departure is justified, however, because the presumption
of integration is now shared with new customer-owned facilities,
shifting to the transmission provider the burden of demonstrating that
credits for similar customer-owned facilities are not warranted.
---------------------------------------------------------------------------

    \48\ See Order No. 890-A at P 351.
    \49\ FP&L, 74 FERC at 61,010 (finding that the integration of
facilities into the plans or operations of a transmitting utility is
the proper test for cost recognition).
---------------------------------------------------------------------------

    66. We reject the suggestion by E.ON U.S. to reestablish a link
between credits and joint planning by applying the presumption of
integration only to upgrades planned through the transmission
provider's Attachment K process. Although we support coordinated, open,
and transparent planning, transmission providers are not required to
develop transmission plans on a co-equal basis with customers.\50\ It
would therefore be unfair to network customers to condition the receipt
of credits for new facilities on planning activities that are out of
their control. Indeed, restablishing a link between joint planning and
credits would revive disincentives the Commission sought to correct by
severing the link between planning and credits in Order No. 890. We
therefore affirm our decision to sever the link between credits and
joint planning.
---------------------------------------------------------------------------

    \50\ Order No. 890-A at P 188.
---------------------------------------------------------------------------

    67. To the extent necessary, we clarify that none of the reforms
regarding transmission credits adopted in Order No. 890 were intended
to apply to facilities existing prior to the effectiveness of the
revised section 30.9 nor to pending cases involving such facilities.
Denial of credits to a network customer's previously existing
facilities therefore still triggers review of the transmission
provider's rate base. Similarly, a network customer may not rely on the
presumption of integration for its previously existing facilities.
3. Capacity Reassignment
    68. In Order No. 890-A, the Commission granted rehearing of its
decision in Order No. 890 to remove the price cap on reassignments of
transmission capacity, concluding that it is more appropriate to allow
reassignments above the cap only during a study period ending on
October 1, 2010. The Commission directed staff to closely monitor the
development of the secondary market for transmission capacity during
this period. To assist staff in this effort, the Commission affirmed
the requirement for transmission providers to aggregate and summarize
in an electronic quarterly report (EQR) the data contained in service
agreements and related OASIS schedules for reassigned capacity. The
Commission also directed staff to prepare a report on staff's findings
within 6 months of the receipt of two years worth of data, i.e., by May
1, 2010. Upon review of the staff report and any feedback from the
industry, the Commission will determine whether it is appropriate to
continue to allow reassignments of capacity above the price cap beyond
the study period. In the absence of further Commission action, the
price cap will resume effect as of October 1, 2010 under section 23.1
of the pro forma OATT.
    69. The Commission clarified in Order No. 890-A that, as of the
effective date of the reforms adopted in Order No. 890, all
reassignments of capacity must take place under the terms and
conditions of the transmission provider's OATT. As a result, there is
no longer a need for the assigning party to have on file with the
Commission a rate schedule governing reassigned capacity. To the extent
that a reseller has a market-based rate tariff on file, the provisions
of that tariff, including a price cap or reporting obligations, will
not apply to the reassignment since such transactions no longer take
place pursuant to the authorization of that tariff.
Request for Rehearing
    70. The APPA Joint Filers argue on rehearing that the decision to
remove the price cap for reassignments of transmission capacity during
the study period is not supported by substantial evidence that the
price cap has discouraged development of a secondary transmission
market.\51\ The APPA Joint Filers also contend that lifting the price
cap on reassigned capacity will harm consumers by making transmission
artificially scarce and overpriced. The APPA Joint Filers argue that
the existence of congestion creates constrained regions within which
market power can be exercised.
---------------------------------------------------------------------------

    \51\ The APPA Joint Filers include: APPA, NRECA, TAPS and TDU
Systems.
---------------------------------------------------------------------------

    71. To further protect consumers, the APPA Joint Filers suggest
that the Commission limit the experimental lifting of price caps to
short-term reassignments.\52\ The APPA Joint Filers state that long-
term firm point-to-point transmission service is particularly important
to LSEs looking to secure economic and reliable power supply and that
non-firm releases of unscheduled transmission capacity will not help
those LSEs needing long-term firm service. The APPA Joint Filers also
argue that, by extending the experiment to long-term sales, including
reassignments by the transmission provider's merchant function or
affiliate, the Commission has discouraged needed transmission
construction. If the secondary market is clearing at prices above the
transmission provider's rate ceiling, the APPA Joint Filers contend
that the parent corporation will have incentives to put as much
capacity in the hands of its merchant function or affiliates as
possible and to avoid new transmission construction. That result, the
APPA Joint Filers argue, would reduce the access of LSEs to the long-
term firm transmission service they require to meet their service
obligations, in violation of FPA section 217(b)(4). The APPA Joint
Filers suggest that the Commission can achieve its goal of determining
whether the price cap encourages development of a secondary market and
whether there is competition in such a market by lifting the price cap
only for short-term reassignments.
---------------------------------------------------------------------------

    \52\ Citing Interstate Natural Gas Ass'n of Am. v. FERC, 285
F.3d 18 (D.C. Cir. 2002).
---------------------------------------------------------------------------

    72. The APPA Joint Filers also contend that the affirmative
obligation

of the transmission provider to expand its system in order to
accommodate requests for service is inadequate to ensure customers are
protected. The APPA Joint Filers note that this obligation has existed
since 1996, yet the Commission in Order No. 890 found that it had not
succeeded in overcoming transmission providers' incentives to avoid
transmission investment, especially in favor of their own
generation.\53\ The APPA Joint Filers contend that the Commission has
no factual basis to conclude that entry in the form of expanded
transmission capacity will be timely, likely and sufficient to defeat
price increases due to transmission market power.
---------------------------------------------------------------------------

    \53\ Citing Order No. 890 at P 424.
---------------------------------------------------------------------------

    73. The APPA Joint Filers acknowledge that Commission staff will be
monitoring the EQRs and other data during the two-year period with the
goal of preparing its report, but argue that this does not alleviate
the Commission of its obligation to actively monitor resale of
transmission capacity during the period to ensure that rates for
customers remain just and reasonable and that there are no abuses of
market power. The APPA Joint Filers ask the Commission to explicitly
establish its intent to continue to exercise its obligations under
sections 205 and 206 throughout this period so that resellers are on
notice that they cannot charge unjust and unreasonable rates. If the
Commission discovers evidence of unjust and unreasonable rates at any
time, the APPA Joint Filers urge the Commission to address this as it
occurs, including if necessary by terminating the experiment prior to
October 1, 2010.
    74. With regard to the staff report, the APPA Joint Filers ask the
Commission to prescribe the parameters, procedures and data to be
collected and provide guidance as to the issues that should be
addressed. The APPA Joint Filers suggest that the Commission direct
staff to address the following specific matters in the report: Identify
whether there is an increase in reassignments by examining data on the
amount of reassignments before and after the price caps were lifted;
examine prices both offered and accepted to determine the level of
market interest in reassigned capacity, whether prices increased, the
cause of price changes, and whether prices remained within a zone of
reasonableness; examine whether competition among resellers is
sufficient to protect consumers from excessive rates; identify the
kinds of products resold, such as the length of reassignments and
whether reassigning customers redirected service; consider whether
reservations by the transmission provider's merchant function or
affiliates increased, whether they reassigned the capacity reserved,
and to whom and at what price they reassigned service; indicate whether
the transmission provider's interactions with affiliated resellers were
covered by the Standards of Conduct; and, assess whether those needing
transmission capacity were able to obtain it, whether in the primary or
secondary market.
    75. To the extent the EQR data or other sources do not provide this
information, the APPA Joint Filers suggest that the Commission
institute data reporting and collection requirements to obtain that
information. The APPA Joint Filers state particular concern regarding
the elimination of the reporting requirement under the reseller's
market-based rate tariff. The APPA Joint Filers contend that lifting
the price cap will allow market-based sellers to use transmission
capacity reassignment to support attempts to exercise market power in
sales of transmission, electricity, or both. Because a market-based
seller no longer needs to report its own transmission reassignments and
because the transmission provider will report reassignments only on an
aggregate, summary basis, the APPA Joint Filers argue that the EQR data
will not permit monitoring to detect patterns or conduct that suggest
efforts to manipulate or exercise market power in transmission markets.
The APPA Joint Filers contend that, by separating data on the market-
based seller's electricity sales from the data on the same seller's
transmission reassignments, the Commission has made it difficult to
determine whether a market-based seller is manipulating transmission
resales to favor its market-based sales because it will be impossible
to determine whether a particular capacity reassignment supported a
market-based sale. The APPA Joint Filers therefore request that the
Commission grant rehearing and retain the requirement that all holders
of market-based rate authority report both their electricity sales and
their capacity reassignments in the same EQR.
    76. Finally, once the staff report is issued, the APPA Joint Filers
ask that it be noticed and that the public be provided an opportunity
to comment. The APPA Joint Filers contend that the data underlying the
report must be made public, with sensitive information subject to
appropriate confidentiality protections. If the Commission believes
that further extension of the experiment is merited, the APPA Joint
Filers ask the Commission to use full notice and comment rulemaking
procedures to ensure a complete record is developed to support any
further Commission action.
Commission Determination
    77. The Commission affirms its decision to remove the price cap on
reassignments of transmission capacity to accommodate a study period
expiring on October 1, 2010. For the reasons stated in Order Nos. 890
and 890-A, we continue to believe that lifting the price cap during the
study period will foster the development of a more robust secondary
market for transmission capacity.\54\ Point-to-point transmission
service customers will have increased incentives to make their service
available to others that place a higher value on it, which in turn will
send more accurate signals that promote efficient use of the
transmission system by fostering the reassignment of unused capacity.
---------------------------------------------------------------------------

    \54\ Order No. 890 at P 808; Order No. 890-A at P 388-89.
---------------------------------------------------------------------------

    78. Although the Commission agrees with the APPA Joint Filers that
transmission capacity, and in particular long-term transmission
capacity, is of great importance to LSEs and other customers, we
disagree that restricting transactions above the price cap only to
short-term reassignments is necessary to preserve access to service
under the pro forma OATT. As the Commission emphasized in Order Nos.
890 and 890-A, transmission providers are under an affirmative
obligation to offer all available capacity to customers on a non-
discriminatory basis and to expand their systems as necessary to
accommodate additional requests for service.\55\ The pro forma OATT
does not, and will not, permit the withholding of transmission capacity
by the transmission provider and effectively establishes a price
ceiling for long-term reassignments at the transmission provider's cost
of expanding its system. The fact that a transmission provider's
affiliate may profit from congestion on the system does not relieve the
transmission provider of its obligation to offer all available
transmission capacity and expand its system as necessary to accommodate
requests for service. We therefore disagree that allowing reassignments
of transmission capacity above the price cap will reduce the access of
any customer to service under the pro forma OATT.
---------------------------------------------------------------------------

    \55\ Order No. 890 at P 814; Order No. 890-A at P 392.
---------------------------------------------------------------------------

    79. The APPA Joint Filers are therefore incorrect that lifting the
price cap will make transmission capacity

artificially scarce and overpriced during the study period.
Transmission providers must continue to make primary capacity available
at the rates specified in their individual OATTs. Customers that do not
wish to participate in the secondary market may continue to take
service from the transmission provider directly, just as if the price
cap had not been lifted. For those customers participating in the
secondary market, however, lifting the price cap will create additional
incentives for others to make service available, increasing the ability
to obtain transmission capacity.
    80. The APPA Joint Filers incorrectly characterize the Commission's
statement in paragraph 392 of Order No. 890 as finding that the
transmission provider's obligation to expand the system in response to
service requests was inadequate to overcome incentives to avoid
transmission investment. In the passage cited, the Commission instead
found that this requirement was inadequate to overcome incentives to
exclude customers from the transmission planning process.\56\
---------------------------------------------------------------------------

    \56\ Id. P 424.
---------------------------------------------------------------------------

    To remedy that disincentive, the Commission required transmission
providers to implement open and transparent planning processes that
allow customers and other stakeholders to provide input in the
development of transmission plans. The Commission specifically noted
that those planning obligations did not address or dictate which
investments identified in a transmission plan should be undertaken by
the transmission provider.\57\
---------------------------------------------------------------------------

    \57\ Id. P 438.
---------------------------------------------------------------------------

    81. The APPA Joint Filers inappropriately discount the importance
of the transmission provider's affirmative obligation to expand its
system in response to requests for service. The Commission has
historically relied on these and other obligations under the pro forma
OATT sufficient to mitigate the potential exercise of transmission
market power by transmission providers and their affiliates.\58\
Lifting the price cap on reassignments of transmission capacity does
not alter those obligations in any way and, therefore, does not impair
the ability of load-serving entities to meet their load service
obligations. By lifting the price cap on capacity reassignments, the
Commission has instead enhanced the options available to customers
seeking transmission service by increasing the incentives for customers
with transmission reservations to make capacity available to others
placing a higher value on it.
---------------------------------------------------------------------------

    \58\ See Order No. 697 at P 408.
---------------------------------------------------------------------------

    82. We are nevertheless sensitive to the concerns expressed
regarding the potentially negative competitive effects of lifting the
price cap on reassignments of transmission capacity. It is for that
very reason that the Commission granted rehearing in Order No. 890-A,
at the request of the APPA Joint Filers, to limit the period in which
the price cap is lifted. During the study period, continuing rate
regulation of the transmission provider's primary capacity, competition
among resellers, and reforms to the secondary market for transmission
capacity, combined with enforcement proceedings, audits, and other
regulatory controls, will assure that prices in the secondary market
remain within a zone of reasonableness.\59\ Should any customer believe
that capacity is being preferentially allocated to a transmission
provider's affiliates, that particular holders of transmission capacity
are attempting to exercise market power through hoarding or other
tactics, or that the transmission provider is failing to meet its
expansion obligations, the customer should bring the matter to the
Commission's attention through a complaint or other appropriate
procedural mechanisms. If the Commission finds evidence of market
abuse, it can act to restrict the ability of an offending reseller (and
possibly its affiliates) to participate in the secondary market or
impose other remedies, including civil penalties, as appropriate to
ensure that rates for secondary transmission capacity are just and
reasonable.
---------------------------------------------------------------------------

    \59\ See Order No. 890 at P 811; Order No. 890-A at P 391.
---------------------------------------------------------------------------

    83. With respect to our expectations for the report to be prepared
by Commission staff, we clarify that staff should focus on the
competitive effects of removing the price cap for reassigned capacity.
Staff should consider the number of reassignments occurring over the
study period, the magnitude and variability of resale prices, the term
of the reassignments, and any relationship between resale prices and
price differentials in related energy markets. Staff should also
examine the nature and scope of reassignments undertaken by the
transmission provider's affiliates and include in its report any
evidence of abuse in the secondary market for transmission capacity,
whether by those affiliates or other customers.\60\
---------------------------------------------------------------------------

    \60\ See id. P 406.
---------------------------------------------------------------------------

    84. As requested by the Joint APPA Filers, we have reconsidered our
reporting requirements and determined that it would be useful to direct
transmission providers to include certain additional information in
their EQRs. We direct transmission providers to include in their EQRs
the identity of the reseller and indicate whether the reseller is
affiliated with the transmission provider. Each transmission provider
also must include the rate that would have been charged under its OATT
had the secondary customer purchased primary service from the
transmission provider for the term of the reassignment. We direct
transmission providers to submit this additional data for all resales
during the study period and to update, as necessary, any previously-
filed EQRs on or before the date they submit their next EQR.
    85. We disagree that elimination of the reporting requirement under
the reseller's market-based rate tariff will impair the ability of
staff to perform its analyses. All reassignments of transmission
capacity now take place under the transmission provider's OATT and,
therefore, it is appropriate for the transmission provider to report
those transactions on its EQR. We reiterate that the EQR must contain
all relevant transaction data, whether stated in the service agreement
governing the reassignment or in a related OASIS schedule.\61\
Transmission providers should not aggregate multiple transactions into
single line items on the EQR. All terms must instead be fully described
and rates provided for each reassignment.\62\
---------------------------------------------------------------------------

    \61\ See Order No. 890 at P 423, n.162.
    \62\ See Order No. 890 at P 818, n.499. The Commission's
reference to ``aggregate[ing] and summarize[ing] in an EWQ the data
contained in the service agreements for reassigned capacity'' in
Order Nos. 890 and 890-A was intended to refer to the transmission
provider's obligation to compile reassignments involving multiple
parties in a single EQR, not consolidate multiple reassignments into
single line items on the EQR.
---------------------------------------------------------------------------

    86. Upon review of the staff report, the Commission will determine
whether it is appropriate to institute further rulemaking procedures to
amend the pro forma OATT to allow reassignments of transmission
capacity above the price cap after October 1, 2010. The report will be
made public and subject to comment, with sensitive information subject
to appropriate confidentiality protections. In the absence of
Commission action, the rate charged by the transmission provider for
each reassignment, and the corresponding credit to the reseller, may
not exceed the higher of (i) the original rate paid by the reseller,
(ii) the transmission provider's maximum rate on file at the time of
the assignment, or (iii) the reseller's

opportunity cost capped at the transmission provider's cost of
expansion.\63\
---------------------------------------------------------------------------

    \63\ See section 23.1 of the pro forma OATT.
---------------------------------------------------------------------------

4. Operational Penalties
    87. In Order No. 890-A, the Commission affirmed the decision in
Order No. 890 to subject all transmission providers, including RTOs and
ISOs, to operational penalties when they routinely fail to meet the
deadlines prescribed in sections 19.2, 19.4, 32.3 and 32.4 of the pro
forma OATT. The Commission explained that the 60-day due diligence
deadlines set forth in those sections serve as a good measure of a
transmission provider's use of due diligence since, in its experience,
the vast majority of transmission studies can be completed in that time
period.
    88. The Commission rejected requests to change section 19.9 of the
pro forma OATT, concluding that transmission providers will have the
ability to explain in notification filings the extenuating
circumstances that lead to delay in processing transmission service
request studies and, in turn, demonstrate their use of due diligence
notwithstanding the inability to meet the 60-day target. The Commission
also rejected requests to create broad categories or lists of
extenuating circumstances that would exempt transmission providers from
late study penalties or related posting requirements.
Requests for Rehearing and Clarification
    89. E.ON U.S., EEI, and Southern contend that the Commission has
failed to justify the use of 60 days as the time frame for processing
transmission service request studies with due diligence. These
petitioners argue that the Commission's stated experience that the vast
majority of studies are completed within 60 days is unsupported by data
or any other evidence. Southern further argues that any experience
regarding processing times does not reflect the increased redispatch
and conditional firm study obligations imposed under Order No. 890.
Southern argues that transmission planners are also facing additional
workforce pressures due to development of reliability standards, worker
shortages, and Attachment K planning processes. Southern suggests that
the Commission grant rehearing to allow for an additional 30 days to
process transmission studies or, at a minimum, to process conditional
firm and redispatch options. Southern acknowledges that the Commission
determined in Order No. 890-A that the mere possibility of penalties
did not justify extension of the 60-day study period. Southern argues,
however, that the notification and additional posting requirements are
in and of themselves penalties, as are the requirements to then
complete 90 percent of studies within 60 days.
    90. E.ON U.S., EEI, and Southern also ask the Commission to add a
clearer due diligence standard to section 19.9 of the pro forma OATT.
They contend that it is necessary to specify in the tariff the
circumstances that will excuse the transmission provider from
penalties. These petitioners argue that failure to articulate a clear
standard gives the Commission too much discretion in applying penalties
and leaves transmission providers guessing as to what due diligence
means. Southern argues that a lack of clarity violates due process and
the Commission's enforcement policies because transmission providers do
not have adequate notice of the circumstances that will subject them to
penalties. Southern contends that the risk of late study penalties
creates a guilty until proven innocent standard that will result in
transmission providers favoring speed over accuracy, which could harm
reliability.
    91. EEI agrees that failure to expressly include a due diligence
standard in section 19.9 provides the Commission undue discretion to
apply penalties even if the transmission provider has used due
diligence in processing request studies. EEI argues that the language
of section 19.9 does not adequately reflect that the inability to
complete a study within the 60-day timeframe may be due to customer
actions or the need to complete other interdependent studies. At a
minimum, EEI asks the Commission to amend section 19.9(iii) to state
that the transmission provider will not be subject to penalties if it
demonstrates that it exercised due diligence but nonetheless failed to
complete a sufficient percentage of its studies within 60 days. EEI
also requests that the Commission provide additional guidance in this
proceeding as to what factors constitute due diligence that are
sufficiently clear and specific that a transmission provider can
reasonably determine whether its actions satisfy those guidelines.
    92. E.ON U.S., EEI, and Southern further argue that operational
penalties should not be imposed until the Commission makes an
affirmative finding that the transmission provider did not exercise due
diligence in processing request studies. EEI and Southern argue that
due process and the Commission's enforcement policies require notice
and hearing procedures prior to application of penalties. If a
transmission provider fails to complete 90 percent of studies within a
60-day period, EEI suggests that the transmission provider be
rebuttably presumed to have failed to exercise due diligence in
processing request studies and that penalties apply only after notice
and an opportunity for hearing.
    93. Southern suggests that the explanation of extenuating
circumstances in a notification filing should automatically suspend the
obligation to post additional metrics, the obligation to process 90
percent of study requests within 60 days, and the threat of monetary
penalties until the Commission determines that the extenuating
circumstances did not exist. Southern states that this would shift the
burden of proof to the Commission and no longer treat transmission
providers as guilty until proven innocent. E.ON U.S. argues that
deferring the obligation to pay penalties until after the Commission
has rejected the transmission provider's explanation for delay would be
more efficient because transmission providers would not need to seek
refunds from customers to whom it has made distribution of penalties
for delays the Commission later finds justifiable.
    94. E.ON U.S. seeks clarification that not-for-profit transmission
providers are responsible for processing transmission request studies
within the same time period prescribed for other transmission providers
and are equally responsible for paying late study penalties. E.ON U.S.
argues that the ability to request cost recovery of late study
penalties on a case-by-case basis should not be used to skirt the
obligations established in Order No. 890.
    95. NYISO asks the Commission to clarify that it did not intend in
Order No. 890-A to preclude transmission providers from proposing
alternative study deadlines pursuant to FPA section 205. NYISO states
that, because it provides a financial reservation based transmission
service reservation, it does not receive, or deny, requests for
transmission service in the way that Order Nos. 888 and 890
contemplate. NYISO states it conducts transmission studies only in
unusual situations, such as when a customer wants to explore whether it
would be more economical to pay congestion charges or to fund the
construction of new transmission facilities in order to obtain
incremental congestion hedging rights from NYISO. As a result, only a
handful of system impact study requests have been submitted to the
NYISO in the last nine

years and, according to NYISO, each take substantial time to process.
    96. NYISO also requests clarification regarding the transmission
provider's liability when delegating responsibilities for conducting
transmission studies. NYISO states that it has responsibility for
conducting system impact studies under its OATT, while its member
transmission owning utilities retained responsibility for conducting
facilities studies. NYISO asks the Commission to clarify that its
member transmission owning utilities are responsible for ensuring that
facilities studies are conducted in a timely manner. NYISO argues that
it would be arbitrary and capricious to hold NYISO responsible for
failures by the member transmission-owning utilities to comply with
their own obligations.
Commission Determination
    97. The Commission affirms the decision in Order Nos. 890 and 890-A
to subject transmission providers to operational penalties when they
routinely fail to meet the 60-day due diligence deadlines prescribed in
sections 19.2, 19.4, 32.3, and 32.4 of the pro forma OATT.\64\
Transmission providers must have a meaningful stake in meeting study
timeframes, and the operational penalty structure adopted by the
Commission provides reasonable financial incentives for transmission
providers to exercise due diligence in processing service requests in a
timely and nondiscriminatory manner.
---------------------------------------------------------------------------

    \64\ See Order No. 890 at P 1340; Order No. 890-A at P 741.
---------------------------------------------------------------------------

    98. We disagree that the notice procedures adopted in Order No. 890
give inadequate opportunities to explain why studies have been
completed late. Due process does not require the use of notice and
hearing procedures prior to applying operational penalties for failing
to exercise due diligence in processing transmission service request
studies within the 60-day study period, nor must the Commission make an
affirmative finding regarding the justifications provided in a
notification filing prior to the application of penalties. Section 19.9
of the pro forma OATT requires the submission of a notification filing
and the application of penalties when certain clearly identified
triggering conditions occur, i.e., failure to complete studies within
the prescribed timeframes. Transmission providers therefore have
adequate notice of the actions that may lead to penalties. We note that
transmission customers that pay other operational penalties, like
unreserved use penalties, do not receive notice or have hearing
procedures prior to paying the penalty.
    99. At the same time, to ensure that penalties are not applied to
transmission providers when study delays are justified, the Commission
has provided an opportunity for each transmission provider to explain
the extenuating circumstances that prevented it from meeting the 60-day
study completion deadline. Upon review of the notification filing, the
Commission will waive the penalties if a transmission provider
establishes that its non-compliance is the result of extenuating
circumstances.\65\ If the Commission is unable to act on the
notification filing prior to the date on which the penalties would
apply, the transmission provider will remain liable for paying the
penalties, but is not required to distribute those penalties while the
notification filing remains pending.\66\ The Commission concluded in
Order No. 890, and we affirm here, that this adequately balances the
transmission provider's due process rights with the need to provide an
incentive to the transmission provider to complete studies on a timely
basis.\67\ It is therefore unnecessary, as petitioners argue, to amend
the language of section 19.9 of the pro forma OATT to specifically
include a due diligence standard or otherwise identify in the tariff or
elsewhere the circumstances that will excuse the transmission provider
from penalties. Consideration of the particular extenuating
circumstances causing a transmission provider to repeatedly miss study
deadlines is best left to a case-by-case analysis.
---------------------------------------------------------------------------

    \65\ See Order No. 890 at P 1343.
    \66\ See id. P 1349.
    \67\ Id.
---------------------------------------------------------------------------

    100. We also affirm the decision in Order No. 890-A not to extend
the 60-day deadline as petitioners request.\68\ The 60-day deadlines
have existed for many years.\69\ Although petitioners challenge that
conclusion as unsupported, none dispute the proposition that 60 days is
generally sufficient to complete most transmission studies and,
instead, contend that certain types of studies take longer or that
certain transmission providers have less ability to process studies
within that period. Yet that is precisely why the Commission has
provided an opportunity for each transmission provider to demonstrate
that extenuating circumstances prevented it from timely processing the
relevant studies notwithstanding its inability to meet the 60-day
target. Transmission providers are free to discuss in their
notification filings any factors they believe are relevant, including
any of the factors cited by Southern.
---------------------------------------------------------------------------

    \68\ Order No. 890-A P 746.
    \69\ See Order No. 888-A at 30,324.
---------------------------------------------------------------------------

    101. In response to E.ON U.S., we affirm that all transmission
providers, including RTOs and ISOs, are bound by the 60-day timelines
of sections 19.2, 19.4, 32.3 and 32.4 and the requirements of section
19.9. The Commission clarifies, in response to NYISO, that transmission
providers are free to make filings under FPA section 205 to seek
variations from the pro forma OATT and demonstrate that alternative
tariff provisions are consistent with or superior to the pro forma
OATT. With regard to the allocation of study responsibilities between
NYISO and its transmission owning members, we note that the Commission
in Docket No. OA08-13-000 determined that the responsibility for
facility studies, and penalties associated with such studies, rests
with the transmission owning members under the NYISO tariff.\70\
---------------------------------------------------------------------------

    \70\ See N.Y. Indep. Sys. Operator, Inc., 123 FERC ] 61,134
(2008).
---------------------------------------------------------------------------

5. ``Higher Of'' Pricing Policy
    102. In Order No. 890, the Commission concluded that changes to the
pro forma OATT were not needed to address the practice by some
transmission providers of quoting incremental rates as lump sum
payments, a practice that is inconsistent with our ratemaking policy.
The Commission explained that the transmission provider must continue
to include a proposed monthly incremental rate with its offer of
service whenever it proposes to charge the customer an incremental
rate. The transmission provider also must provide cost support for the
derivation of the rate consistent with the cost support that the
transmission provider would provide to the Commission in a section 205
rate filing.
    103. The Commission affirmed this decision in Order No. 890-A,
noting that the capital costs of upgrades, as estimated in a facilities
study and eventually specified in a service agreement through an
incremental rate, are not subject to change once the customer has
executed the service agreement. The Commission explained that it would
not be appropriate to vary capital costs over the term of such
contracts.
Request for Rehearing
    104. Duke, E.ON U.S., and EEI argue that the Commission's statement
that

capital costs of network upgrades may not vary during the term of a
service agreement is inconsistent with other sections of the pro forma
OATT. Duke notes that section 19.4 of the pro forma OATT requires
execution (or filing) of a service agreement a mere thirty days after
completion of the facilities study and, therefore, the service
agreement can only contain a good faith estimate of network upgrade
costs. EEI and E.ON U.S. agree, noting section 19.5 further allows for
revisions to the good faith estimate to reflect certain changed
circumstances. EEI and E.ON U.S. contend that transmission providers
generally are not able to determine the actual cost of required
facilities until construction is completed, which is long after
execution of the service agreement.
    105. EEI and E.ON U.S. argue that not allowing capital costs of
upgrades to vary after execution of the service agreement will result
in the transmission provider either under-recovering the cost of the
incremental facilities or the customer overpaying the cost of those
facilities and, as a result, charges will not be just and reasonable.
These petitioners suggest that the transmission provider be allowed to
modify a service agreement to reflect the actual costs of
incrementally-charged network upgrades after the facilities are placed
in service. Duke agrees, arguing that providing for a true-up at a
later date is routine when facility costs are directly assigned, rather
than rolled in. Duke suggests that customers be free to negotiate the
ability to terminate the service agreement if a cost estimate turns out
to far understate actual costs. Duke contends that the Commission's
statement regarding the inability of capital costs to vary was merely a
general observation and that the Commission should review rate changes
on a case-by-case basis.
    106. Duke, EEI, and E.ON U.S. further argue that prohibiting
recovery of additional capital costs that the transmission provider is
likely to incur when repairing or replacing portions of incrementally-
charged upgrades during the term of a service agreement denies the
transmission provider of its rights under section 205 of the FPA. While
the incremental facilities on which the cost of service is based (e.g.,
a specific substation or line segment) should not be allowed to vary,
EEI contends that transmission providers should be allowed recover the
additional capital costs associated with repair or replacement of those
facilities. EEI and E.ON U.S. suggest that remedies such as formula
rates or a section 205 filing should be available to a transmission
provider to recover these additional costs.
Commission Determination
    107. The Commission affirms the determination in Order No. 890 that
capital costs specified in a service agreement are not subject to
change once the customer has executed the service agreement.\71\ We
clarify, however, that this statement was intended to refer to
agreements in which a customer and transmission provider have
specifically identified particular upgrade costs to be paid by the
customer, allowing for a clear comparison of incremental costs to the
transmission provider's embedded cost rate. In such instances, it would
violate fundamental concepts of contract law, as well as undermine the
``higher of'' pricing policy, to allow either the customer or the
transmission provider to unilaterally change the costs previously
agreed to by the parties. The Commission therefore explained in Order
No. 890-A that it would not be appropriate to vary, i.e., change,
capital costs specified in such contracts.
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    \71\ See Order No. 890-A at P 491.
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    108. Nothing in Order Nos. 890 or 890-A, however, altered the
ability of the transmission provider and transmission customer to
negotiate alternative pricing arrangements such as recovering estimated
costs subject to a true-up when upgrades are complete. The Commission
did not mean to imply in Order No. 890-A that such alternative pricing
arrangements are necessarily prohibited. As the Commission explained in
Order No. 890, application of the ``higher of'' policy to particular
cases, including proposals to adopt flexible pricing arrangements, is
largely fact-specific and best addressed on a case-by-case basis during
particular rate proceedings.\72\
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    \72\ See Order No. 890-A at P 883.
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6. Other Ancillary Services
    109. In Order No. 890-A, the Commission denied a request by Sempra
Global to require the transmission provider to offer and make available
operating reserves under schedules 5 and 6 of the pro forma OATT when
transmission service is used to serve load outside the transmission
provider's control area. The Commission explained that operating
reserves are needed to serve load within the control area in the event
of system contingencies and, unless alternative arrangements are made,
the transmission provider provides these reserves from its own
resources. The Commission found that it would be inappropriate to
require the transmission provider to use its resources to provide
additional operating reserves to loads in other control areas because
the transmission providers in those control areas are under their own
obligations to make operating reserves available. The Commission
affirmed those obligations and stated that modifications to the pro
forma OATT were not necessary to enable generators to engage in firm
power sales to loads outside of their control area.
Request for Clarification
    110. Sempra Global argues that the Commission did not fully
appreciate the problems faced by generators in obtaining operating
reserves in the WECC. If transmission providers are not required to
offer operating reserves when transmission service is used to serve
load outside the transmission provider's control area, Sempra Global
asks that the Commission, at a minimum, clarify that generator
imbalance service under Schedule 9 of the pro forma OATT may be
utilized to provide sufficient imbalance energy to keep a customer's
schedule whole for at least two hours following a generator derating or
forced outage, if necessary to allow the generator sufficient time to
find and schedule replacement energy. Sempra Global states that
clarification is needed because, if a generator trips within 20 minutes
prior to the beginning of the hour, it is too late to schedule
replacement energy for the hour that is about to begin.
    111. Sempra Global disagrees that the existing requirements of the
pro forma OATT are sufficient to ensure that operating reserves are
available to merchant generators in the WECC, pointing to the differing
definitions for ``reserves'' in the West. Sempra Global explains that
in the WECC ``Operating Reserves'' consist of two main components:
Regulating Reserve and Contingency Reserve.\73\ According to Sempra
Global, WECC's Regulating Reserve could include, but would not
necessarily be limited to, regulation service offered under schedule 3
of the pro forma OATT, while WECC's Contingency Reserve could include,
but would not necessarily be limited to, operating reserve services
under Schedules 5 and 6 of the pro forma OATT.
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    \73\ Citing WECC Standard BAL-STD-002-0--Operating Reserves.
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    112. Although independent power generators have access to
regulation service under schedule 3 and generator

imbalance service under Schedule 9 from their source balancing
authority, Sempra Global states that they may not have access to any
Contingency Reserves for exports from their host balancing authority.
Sempra Global contends that it can be difficult, if not impossible, for
generators to contract for Contingency Reserves from a third party
without switching to that party's balancing authority or having a
dynamic schedule or other telemetry to enable the provider of
Contingency Reserves to know when the generator trips and to have the
reserves provider's generation respond within ten minutes. Sempra
Global contends that intra-hour schedule changes are not normally
allowed by most balancing authorities in the West and that Operating
and/or Contingency Reserve service can most logically be provided to a
balancing authority or reserve sharing group, not an individual
customer. Sempra Global states that this complex type of arrangement
could not be practicably implemented for short-term transactions, or
when the output of a generator is split between multiple buyers and
ultimately delivered into multiple balancing authorities.
    113. Even if a generator were able to contract with a third party
to provide operating reserves, Sempra Global states that it is unaware
of any workable mechanism to assure a load (or ``sink'') balancing
authority that it will have access to such reserves when needed. Sempra
Global also notes that a generator, as a seller, may not necessarily
have a load since transactions frequently involve numerous parties
between the generator and the load. Sempra Global states that a
generator may not know who the load is until the NERC eTags are
generated during the WECC pre-scheduling process, which typically takes
place the day before the power flows. Even if the sink balancing
authority is known at the time a long-term transaction is entered into,
Sempra Global states that a generator still may be unable to procure
operating reserves to support the transaction. Sempra Global describes
a transaction it entered into in 2002 in which none of the host
transmission provider, the purchaser's transmission provider, nor the
purchaser itself was willing to offer to provide Sempra Global with
operating reserves to support the transaction. Since many LSE
purchasers in the West enter into firm energy import transactions
specifically to reduce their operating reserves obligations, Sempra
Global states that it would be rarely fruitful for a generator to
request, as part of its negotiation with a customer, that the customer
acquire reserves from its transmission provider.
Commission Determination
    114. The Commission affirms the decision in Order No. 890-A not to
require transmission providers to offer and make available operating
reserves under Schedules 5 and 6 of the pro forma OATT when
transmission is used to serve load outside the transmission provider's
control area. As the Commission explained, operating reserves are
needed to serve load within the control area in the event of system
contingencies. Unless alternative arrangements are made, the
transmission provider would serve as the provider of last resort for
these reserves. We continue to believe it would be inappropriate to
require the transmission provider to provide additional operating
reserves to loads in other control areas because the transmission
providers in those areas are under their own obligation to make
operating reserves available.
    115. We appreciate Sempra Global's concern that these obligations
may be insufficient to enable merchant generators in the WECC to obtain
operating reserves in certain circumstances. Since its adoption,
however, the pro forma OATT has placed the obligation to procure
operating reserves squarely on load.\74\ It appears that market rules
have developed in the WECC in a way that transfers that responsibility
from transmission customers serving load to those providing resources.
It does not follow, however, that the pro forma OATT--a tariff of
general applicability--must be amended to accommodate that regional
practice. To the extent transmission providers in the WECC wish to
amend their tariffs to accommodate the WECC market rules, they may
submit such variations to the Commission for consideration.
Alternatively, the market rules themselves could be amended to reflect
the structure of obligations under the pro forma OATT.\75\
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    \74\ See Section 3 of the pro forma OATT.
    \75\ We understand that WECC is in the process of developing a
revised standard to address the responsibility for procuring
contingency reserves. WECC Standard BAL-002-WECC-1--Contingency
Reserves, available at http://www.wecc.biz/documents/library/
Standards/2007/BAL-002/BAL-002-WECC-1_1-25-08.pdf. To the extent
that there are any conflicts between the revised WECC standard and
the pro forma OATT, Sempra Global should raise those concerns when
that revised standard is submitted for consideration by the
Commission.
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C. Non-Rate Terms and Conditions

1. Modifications to Long-Term Firm Point-to-Point Service
    116. In Order No. 890, the Commission concluded that the methods
for evaluating requests for long-term point-to-point transmission
service may not be comparable to the manner in which transmission
service is planned for bundled retail native load and, therefore, may
no longer be just, reasonable and not unduly discriminatory. To remedy
this potential for undue discrimination, the Commission amended the pro
forma OATT to modify planning redispatch requirements and require
transmission providers, other than most RTOs and ISOs, to offer a
conditional firm option to long-term point-to-point customers. The
Commission affirmed that decision in Order No. 890-A and provided
certain clarifications regarding the transmission provider's obligation
with regard to planning redispatch and conditional firm service.
a. Requirement To Offer Conditional Firm Service
    117. In Order No. 890-A, the Commission denied rehearing of its
decision not to require transmission providers to offer conditional
firm service to network customers. The Commission explained that
network customers can designate network resources any time firm
transmission is available and that the term of the designation can
include periods of less than a year. Network customers can also use
secondary network service to access resources during times when firm
service is not available. The Commission concluded that this
flexibility to use designated network resources and secondary network
service to access undesignated resources already provides a service
that is like conditional firm that can be used to integrate new
resources. The Commission noted, however, that transmission providers
employ automatic devices, such as special protection schemes, to take
resources offline during certain system conditions. The Commission
determined that comparability requires the study of these automatic
devices for network customers seeking to designate network resources
and revised section 32.3 of the pro forma OATT to require the study of
automatic devices at the request of a network customer.
Requests for Rehearing and Clarification
    118. NRECA and TAPS repeat arguments made on rehearing of Order No.
890 that the Commission must make

conditional firm service available to network customers. NRECA contends
that a transmission provider will not reject a resource for its own
bundled retail load simply because it may be unavailable for a few
hours per year due to congestion. NRECA argues that a transmission
provider will, however, reject a request by a network customer to
designate that same resource because of the same limited availability.
NRECA concludes that conditional firm network service is therefore