Preventing Undue Discrimination and Preference in Transmission Service, 39092-39156 [E8-14948]

Agencies

• DEPARTMENT OF ENERGY
• Federal Energy Regulatory Commission

[Federal Register Volume 73, Number 131 (Tuesday, July 8, 2008)]
[Rules and Regulations]
[Pages 39092-39156]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: E8-14948]



[[Page 39091]]

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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

Federal Register / Vol. 73, No. 131 / Tuesday, July 8, 2008 / Rules 
and Regulations

[[Page 39092]]


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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, (202) 502-6540.
Daniel Hedberg (Technical Information), Office of Energy Market 
Regulation, Federal Energy Regulatory Commission, 888 First Street, 
NE., Washington, DC 20426, (202) 502-6243.

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

[[Page 39093]]

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

[[Page 39094]]

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

[[Page 39095]]

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

[[Page 39096]]

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

[[Page 39097]]

made available as required in Order No. 890-A.
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    \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.
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    \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.
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    \25\ Id. P 290.
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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.''

[[Page 39098]]

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\
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    \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.
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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\
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    \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)).
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    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\
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    \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).
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    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

[[Page 39099]]

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.
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    \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).
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    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

[[Page 39100]]

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\
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    \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 t