377. We also adopt TAPS' suggestion to expand the regulations to
include availability of information supporting the disposition of a
transmission provider's own network resource designations and to make
such information available to any eligible customer rather than just to
that customer denied service. In addition, we clarify that a partial
denial of service triggers the requirements as well. Such information
is consistent with the new regulations established by this Final Rule
and will help ensure that customers receive transmission service that
is not unduly discriminatory. The development of a log of service
denials, full or partial, will establish an ongoing record of service
requests and transmission provider responses demonstrating the
transmission provider's provision of nondiscriminatory open access
service. Furthermore, repeated denials of service over a particular
path or flowgate will provide an indication of congestion that can be
used in the transmission planning process. In addition, we agree with
East Texas Cooperatives that postings of denials of service should
indicate whether the requested service was firm or non-firm.
(6) Designation and Termination of Network Resources
NOPR Proposal
    378. In the NOPR, the Commission proposed to require the
transmission provider and network customers to use the transmission
provider's OASIS to request designation of a new network resource and
to terminate the designation of a network resource. This information
would be posted on OASIS for 90 days and be available for audit for a
five-year period. Transmission customers therefore would be able to
query such requests to designate and

terminate a network resource.\214\ The Commission also proposed to
require the transmission provider to post on its OASIS a list of its
current designated network resources and all network customers' current
designated network resources. The list would include the resource name,
geographic and electrical location and amount of capacity of the
designated network resource.
---------------------------------------------------------------------------

    \214\ See 18 CFR 37.6(a)(6).
---------------------------------------------------------------------------

Comments
    379. Several commenters support the Commission's proposal to
require transmission providers and network customers to use the
transmission provider's OASIS to request or terminate designation of
resources, though some indicated that the required network resource
information is currently available via OASIS.\215\ PJM supports the
proposal, provided that the electrical location is based on an industry
standard format and any standard adopted by NERC takes into
consideration possible confidentiality issues when posting the
geographic location of designated network resources.
---------------------------------------------------------------------------

    \215\ E.g., APPA, Exelon, PJM, TAPS, TranServ, and TDU Systems.
---------------------------------------------------------------------------

    380. APPA suggests that reservations related to future load growth
also should be posted so that it is clear to all industry participants
what transmission capacity transmission providers are reserving for
load growth purposes. Williams submits that the list of current
designated resources needs to indicate whether they are for native load
or network customers, or whether they are for meeting forecasted loads
and system emergencies.
    381. TranServ supports the Commission's proposal and indicates that
NAESB is the appropriate forum for development of standards necessary
to support posting the designation and termination of network
resources. TranServ cautions that implementation will require a
sufficient period of time after the practices and standards are
developed and suggests that changes to OASIS should be timed to avoid
peak summer and winter seasons.
    382. Exelon requests that the Commission clarify that transmission
providers and network customers making firm off-system sales may
terminate designation of network resources solely for the term of such
sale and not for other periods of time. During this period of
termination, the firm capacity is posted and made available to other
customers.
    383. Great Northern supports the proposal and requests
clarification that, when a network resource is ``undesignated,'' ATC
will not be set aside in anticipation that it might be designated again
as a network resource in the future. Great Northern requests that the
Commission confirm that new requests to designate network resources,
regardless of the prior designation of those resources, are placed at
the end of the transmission service queue.
    384. Sacramento states that the posting requirements for network
resources are an unnecessary burden and instead recommends that the
transmission provider should be required to identify resources it is
transmitting to native load when it denies a request for transmission
service from a third party.
Commission Determination
    385. The Commission adopts the NOPR proposal and requires
transmission providers and network customers to use OASIS to request
designation of new network resources and to terminate designation of
network resources.\216\ This information shall be posted on OASIS for
90 days and available for audit for a five-year period. Transmission
customers thus shall be able to query requests to designate and
terminate a network resource. This requirement adds valuable
transparency without undue burden, since it is nothing more than
maintaining a database of designation requests made and responded to
electronically. The Commission orders public utilities, working through
NAESB, to develop appropriate templates for OASIS.
---------------------------------------------------------------------------

    \216\ See paragraph 1477, where further detail on using OASIS to
request designation of network resources is provided.
---------------------------------------------------------------------------

    386. The requests for clarifications by Exelon and Great Northern
will not be addressed in this section. These requests are not related
to OASIS postings, but involve changes in tariff language. They are
addressed in section V.D.6 of this Final Rule.
(7) Posting of Unused Transfer Capability
NOPR Proposal
    387. In the NOPR, the Commission reminded transmission providers
that transfer capability associated with transmission reservations that
is not scheduled in real time should be included in non-firm ATC and
posted on OASIS.
Comments
    388. Entegra, TANC, and TDU Systems emphasize the need for the
posting of unused transfer capability. TDU Systems state that the
requirement to post on OASIS all transfer capability associated with
transmission reservations not scheduled in real time furthers not only
the Commission's goals with respect to comparability and transparency
of ATC calculations, but also the Commission's goals in freeing up
access to transmission capacity for transmission customers.
Commission Determination
    389. We affirm our statement in the NOPR proposal acknowledging
that transfer capability associated with transmission reservations that
are not scheduled in real time is required to be made available as non-
firm, and posted on OASIS.
(8) Other OASIS Issues
Comments
    390. MidAmerican, PacifiCorp and Pinnacle contend that the
development of the OASIS posting requirements is technical in nature
and should be addressed by the NERC and NAESB processes.
    391. NRECA recommends that the Commission require public utility
transmission providers to make OASIS data available in a useable,
machine-readable and manipulable format to transmission customers (so
they can be better prepared to make decisions about their transmission
needs) and to the Commission (so that it can monitor the provision of
transmission service). Similarly, Powerex states that posted data must
be in sufficient detail to permit third parties to independently review
and verify ATC postings and treatment of transmission service requests.
    392. Utah Municipals suggest that OASIS sites be as uniform and
compatible as possible and reasonably user-friendly, and that
certificate fees for access to non-public sites be evaluated for
legitimacy. Arkansas Commission and Seattle also express concern over
the OASIS access requirements established by most transmission
providers, which require viewers to purchase certificates or licenses
for the particular computers from which OASIS access is sought.
    393. Williams suggests that all transmission service-related
business practices and local procedures, including the exercise of
discretion or waiver or granting of exception, be posted on the
transmission provider's OASIS. It also suggests that real-time data and
import/export limits by constrained area should be posted on OASIS,
along with line outages

[[Continued on page 12315]]

]

[[pp. 12315-12364]] Preventing Undue Discrimination and Preference in Transmission
Service

[[Continued from page 12314]]

(planned and unplanned), estimated return to service dates and de-rates
of a line.
Commission Determination
    394. In response to NRECA and other commenters regarding the
availability and format of data available on OASIS, we note that
current regulations already require that OASIS data be made available
in a useable, machine-readable user friendly format to transmission
customers. The improvements required in the Final Rule will enhance the
level of detail posted on OASIS and, in turn, transmission customers'
ability to verify the transmission provider's treatment of transmission
requests. Thus, to the extent NRECA or others desire greater
consistency in data formats, they should propose such revisions through
the NERC and NAESB processes.
    395. Regarding comments received expressing concern about the use
of certificates for OASIS access, we believe that the use of such
certificates can be appropriate. However, the Commission reminds
transmission providers that the cost of OASIS access, whether by
registration, certificate or other form of license, should be limited
to a nominal charge, e.g., no more than $100. This nominal fee provides
funding for OASIS maintenance while assuring that all transmission
customers and potential customers will not be denied access because of
excessive fees.
    396. With respect to Williams' request for additional OASIS
postings, we agree that such additional data would be useful to
transmission customers and is already posted on some ISO and RTO Web
sites and, to a lesser extent, on the NERC web site (TLR data).
Therefore, we require that all transmission service-related business
practices and local procedures, including waivers, should be posted on
or made available through OASIS. With respect to real-time data and
import/export limits by constrained area, estimated return-to-service
dates and line de-ratings, we are confident that most of this data is
already required by this Final Rule and shall be provided whenever TTC
and ATC changes in value trigger the posting of a narrative explanation
of the causes of those changes. Moreover, the Final Rule requires a
broad data exchange among transmission providers, including information
on line outages and other data relating to ATC calculations.
Accordingly, we will not require additional OASIS postings for this
data.
(9) CEII
NOPR Proposal
    397. Critical Energy Infrastructure Information (CEII) is
information concerning proposed or existing critical infrastructure
(physical and virtual) that (1) Relates to the production, generation,
transportation, transmission or distribution of energy, (2) could be
useful to a person in planning an attack on critical infrastructure,
(3) is exempt from mandatory disclosure under the Freedom of
Information Act, 5 U.S.C. 552, and (4) does not simply give the
location of the critical infrastructure.\217\ Access to such
transmission related information has been restricted by the
Commission's CEII regulations.\218 \
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    \217\ See Critical Energy Infrastructure Information, Order No.
683, 71 FR 58273 (Oct. 3, 2006), FERC Stats. & Regs. ] 31,228 at P
66 (2006), reh'g pending. We note that the Commission is proposing
to change the definition of CEII in a proceeding in Docket No. RM06-
23-000. See Critical Energy Infrastructure Information, Notice of
Proposed Rulemaking, 71 FR 58325 (Oct. 3, 2006), FERC Stats. & Regs.
] 32,607 (2006).
    \218\ See 18 CFR 388.112-113.
---------------------------------------------------------------------------

    398. In the NOPR, the Commission recognized that the use of the
existing CEII processes could undermine their goal of providing
increased transparency to information necessary to evaluate the use of
the transmission system. As a result, the Commission requested comment
on procedures that could be adopted by transmission providers to
streamline the resolution of CEII concerns and allow timely disclosure
of information from the transmission providers to interested parties.
Comments
    399. APPA and other commenters argue that the additional
information disclosure requirements proposed in the NOPR raise
substantial CEII concerns, and request the Commission to refine its
CEII procedures to allow those with legitimate need for the information
to obtain it on a timely basis.\219\ Bonneville would like to permit
public access for stakeholders to review principles and methods used in
ATC calculations, but only permit limited access, subject to background
checks and non-disclosure agreements, to modeling data that may
compromise infrastructure security. APPA suggests establishing a
process for advance qualification for receipt of such information by
those industry participants with rights to review information on the
customer side of OASIS, without giving blanket public access. TDU
Systems urge the Commission to adopt a streamlined process to ensure
timely resolution of ATC calculation disputes and to adopt measures
that ensure that CEII claims do not unduly restrict information.
---------------------------------------------------------------------------

    \219\ E.g., MidAmerican, Sacramento, Southern, and TVA.
---------------------------------------------------------------------------

    400. EEI and Southern caution that the release of a transmission
provider's explanation of methodologies, practices, and procedures in
Attachment C may not give rise to CEII concerns, but that other
information such as energy infrastructure data, models and assessments
do raise security and confidentiality concerns. They propose that a
transmission provider have the ability to seek confidential treatment
of such information. Allegheny proposes that an independent third party
or Commission staff review and explain ATC calculations to interested
parties without disclosing CEII.
    401. Several commenters believe that much of the information the
Commission proposes to require transmission providers to provide will
not pose CEII concerns.\220\ However, Entergy states that some of the
information requires protection as proprietary information because its
public availability over OASIS would reveal commercially sensitive
information. ISO New England also points out that information relevant
to the ATC calculation may be market-sensitive
---------------------------------------------------------------------------

    \220\ E.g., Nevada Companies, East Texas Cooperatives, PJM, and
TDU Systems.
---------------------------------------------------------------------------

    402. Pinnacle believes the current CEII process is not unduly
burdensome and urges the Commission to continue to apply the existing
CEII procedures, which allow transmission customers with digital
certificates or passwords to access publicly restricted transmission
information.
Commission Determination
    403. The Commission acknowledges that certain data and studies
required to be made public under this Final Rule may contain CEII. The
Commission has a responsibility to protect this information. However,
the Commission agrees with APPA, Bonneville, and TDU Systems that those
with a legitimate need for CEII information must be able to obtain it
on a timely basis. The Commission also shares EEI and Southern's
concerns that the data, models and assessments used to calculate ATC
may contain information that raises security and confidentiality
concerns, and ISO New England and Entergy's concerns about commercial
and market-sensitive information.
    404. In order to provide transparency and avoid undue delays in
providing information to those with a legitimate need for it, the
Commission requires

transmission providers to establish a standard disclosure procedure for
CEII required to be disclosed by this Final Rule. We note that
transmission customers already have digital certificates or passwords
to access publicly restricted transmission information on OASIS.
Transmission providers may set up an additional login requirement for
users to view CEII sections of the OASIS, requiring users to
acknowledge that they will be viewing CEII information. Transmission
providers may require customers to sign a nondisclosure agreement at
the time that the customer obtains access to this portion of the OASIS.
Only information that meets the criteria for CEII, as defined in
section 388.113 of the Commission's regulations,\221\ should be posted
in this section of the OASIS. Transmission providers will be
responsible for identifying CEII and facilitating access to it by
appropriate entities, and the Commission will be available to resolve
disputes if they arise.
---------------------------------------------------------------------------

    \221\ 18 CFR 388.113.
---------------------------------------------------------------------------

(10) Additional Data Posting
NOPR Proposal
    405. To further reduce discretion in calculating ATC/AFC, the
Commission proposed that transmission providers post on OASIS metrics
related to the provision of transmission service under their OATT. In
the NOPR, the Commission proposed to require the monthly posting of (1)
The number of affiliate versus non-affiliate requests for transmission
service that have been rejected and (2) the number of affiliate versus
non-affiliate requests for transmission service that have been made.
This posting would also detail the length of service request (e.g.,
short-term or long-term) and the type of service requested (e.g., firm
point-to-point, non-firm point-to-point or network service). The
Commission sought comments regarding whether it should require
transmission providers to post their underlying load forecast
assumptions for all ATC calculations and, on a daily basis their actual
daily peak load for the prior day. Finally, the Commission asked for
comment on the overall benefit of posting the proposed metrics, on
potential alternative metrics, and on working through NAESB to develop
standards for consistent methods of posting the new requirements on
OASIS.
Comments
    406. PJM and other commenters support the proposal to post data
showing acceptances and denials of transmission service requests of
non-affiliates and affiliates.\222\ However, PJM and Ameren argue that
the affiliate posting requirement should not apply to RTOs and ISOs,
because they are independent, have no affiliates, and lack incentive to
favor one transmission customer over another. MDEA requests
clarification on how the additional posting requirements would be
applied under Entergy's weekly procurement process. Entergy notes on
reply that the Commission has already established metrics to measure
the performance of its weekly procurement process, and the creation of
further metrics are beyond the scope in a generic rulemaking. Entergy
further points out that non-affiliated generating facilities that are
designated as network resources to serve native load also benefit from
transmission service obtained in this manner. It suggests that NAESB is
the best forum for considering such issues and developing specific
procedures for calculating these metrics. TranServ suggests that there
are other useful metrics that NAESB should be directed to define, such
as average time to evaluate requests and confirm requests, and
percentage of requests denied, approved and withdrawn.
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    \222\ E.g., Arkansas Commission, Constellation, MidAmerican,
MDEA, Morgan Stanley, Nevada Companies, NRECA, Suez Energy NA, and
TranServ.
---------------------------------------------------------------------------

    407. PJM notes its support of proposed OASIS posting reforms, but
cautions that all industry groups must have an equitable and
proportionate voice in NAESB if it is requested to develop standards.
It also expresses concern that PJM and other RTOs have established a
practice of posting a significant amount of data for participants' use
in formats and applications which respective members have requested and
approved through stakeholder processes.
    408. APPA points out that the data on transmission denials would be
useful to the Department of Energy (DOE) in reporting on congestion in
its triennial congestion studies to be prepared under FPA section
216(a), and that NAESB may be able to provide standard formats for
disclosure of such data. Some APPA members express a preference for
NERC to develop these standards, while others stress the need for
regional variation in posting requirements.
    409. Ameren questions whether the posting requirement would serve
the Commission's objective of identifying undue discrimination even in
cases where the transmission provider is not an RTO or other
independent transmission provider, because the metrics can lead to
incorrect impressions. MidAmerican also states that the proposed
posting would require sophisticated analysis to yield useful benefits.
    410. EEI is not opposed to the proposal to post metrics on
acceptance and denial of requests for transmission service, but
suggests such information is already available on OASIS and that any
customer or the Commission staff can develop its own metrics. Southern
also states that this data is currently available.
    411. Several commenters support the posting of forecast and actual
daily peak loads.\223\ Ameren states that the proposed requirement
would produce a useful comparison, increase transparency, and provide
the ability to verify that an appropriate amount of capacity is being
set aside for native load. E.ON states that RTO and ISO forecasts and
actual data need to be posted with sufficient granularity to allow for
meaningful comparison of control area and LSE load levels. EEI requests
that the Commission clarify that its proposal to require the posting of
peak loads applies to system-wide loads and not only to the native load
of the transmission provider. It also seeks clarification that the
differences between forecast and actual system peak loads not result in
any repercussions.
---------------------------------------------------------------------------

    \223\ E.g., Ameren, Constellation, E.ON, Nevada Companies,
NRECA, Powerex, Suez Energy NA, TAPS, TDU Systems, and TranServ.
---------------------------------------------------------------------------

    412. APPA members in the East generally favor the proposal to post
the load information, but its members in the West expressed concerns
about the competitive implications of providing such data. Additional
commenters express concern about data confidentiality.\224\ TAPS
contends that providing for data disclosure on a one-day lag basis
would alleviate these commercial concerns, but it also suggests that
the Commission should require the disclosure of projected load forecast
information on request to a customer's non-market employees or agents.
---------------------------------------------------------------------------

    \224\ E.g., E.ON, Entergy, LDWP, and TranServ.
---------------------------------------------------------------------------

Commission Determination
    413. The Commission adopts the proposed requirement to post on
OASIS metrics related to the provision of transmission service under
the OATT. Specifically, transmission providers must post (1) The number
of affiliate versus non-affiliate requests for transmission service
that have been rejected and (2) the number of affiliate versus non-
affiliate requests for

transmission service that have been made. This posting must detail the
length of service request (e.g., short-term or long-term) and the type
of service requested (e.g., firm point-to-point, non-firm point-to-
point or network service). The Commission also will require
transmission providers to post their underlying load forecast
assumptions for all ATC calculations and, to post on a daily basis,
their actual daily peak load for the prior day. The Commission directs
transmission providers to work through NAESB to develop standards for
consistent methods of posting the new requirements on OASIS.
    414. The Commission agrees with PJM and Ameren that affiliate
posting requirements do not apply to RTOs and ISOs, since they do not
have affiliates to transact with. The Commission also agrees with
Entergy that the metrics established for its weekly procurement process
are outside the scope of this proceeding.
    415. In response to Southern's point that the information necessary
to compute the metrics is already available on OASIS, while it is true
that service denial information is available on OASIS for long periods,
request information is not. As such, a customer would need to
continuously download information from OASIS to record the data
sufficient to calculate the metrics on its own. The Commission
concludes that it is not unduly burdensome for transmission providers
to calculate the metrics required by this Final Rule.
    416. With regard to posting of load forecasts and actual daily peak
load, we conclude that such postings are necessary to provide
transparency for transmission customers. We agree with E.ON that RTO
and ISO load data needs to be posted at a sufficient granularity to
allow for meaningful comparison of control area and LSE load levels.
Most RTOs and ISOs post load data for the entire footprint, but few
post it on an LSE or control area basis. We therefore direct ISOs and
RTOs to post load data for the entire ISO/RTO footprint and for each
LSE or control area footprint within the ISO/RTO. This will not create
an undue burden on ISOs and RTOs, since the load data for the entire
footprint is an aggregation of load data across the LSEs or control
areas in the footprint. We also agree with EEI that the peak load
applies to system-wide load, including native load. We direct
transmission providers to post load forecasts and actual daily peak
load for both system-wide load (including native load) and native load,
as this data will be useful to customers and regulators. We deny EEI's
request for a guarantee that transmission providers will not be held
accountable for producing a reasonable load forecast. While we do not
intend to penalize transmission providers for failing to account for
unforeseen circumstances, we retain our ability to investigate any
allegations of manipulation of load forecasts, as this could be used as
a means of inappropriately denying requested transmission service.
    417. The Commission is not convinced by the views of some
commenters that load data has competitive implications. The Commission
notes, as PJM pointed out in its comments, that many RTOs have an
established practice of posting significant amounts of load data for
participants' use, and this data posting has not raised competitive
concerns.

B. Coordinated, Open and Transparent Planning

1. The Need for Reform
    418. Order No. 888 set forth certain minimum requirements for
transmission system planning. For example, Order No. 888 and the pro
forma OATT require that transmission providers plan and upgrade their
transmission systems to provide comparable open access transmission
service for their transmission customers. With regard to network
service, section 28.2 of the pro forma OATT provides that the
transmission provider ``will plan, construct, operate and maintain its
Transmission System in accordance with Good Utility Practice in order
to provide the Network Customer with Network Integration Transmission
Service over the Transmission Provider's Transmission System.'' Section
28.2 also provides that the Transmission Provider shall, consistent
with Good Utility Practice, ``endeavor to construct and place into
service sufficient transfer capability to deliver the Network
Customer's Network Resources to serve its Network Load on a basis
comparable to the Transmission Provider's delivery of its own
generating and purchased resources to its Native Load Customers.''
    419. The pro forma OATT also requires that new facilities be
constructed to meet the service requests of long-term firm point-to-
point customers. Section 13.5 of the pro forma OATT requires the
transmission provider to consider redispatch of the system to relieve
any constraints that are inhibiting a transmission customer's point-to-
point service if it is economical to do so; but if redispatch is not
economical, the transmission provider is obligated to expand or upgrade
its system. This expansion obligation on the part of the transmission
provider for point-to-point service is found in section 15.4 of the pro
forma OATT, which provides that, when a transmission provider cannot
accommodate a request for point-to-point transmission because of
insufficient capability on its system, it will ``use due diligence to
expand or modify its Transmission System to provide the requested Firm
Transmission Service.'' Section 15.4 goes on to provide that ``the
Transmission Provider will conform to Good Utility Practice in
determining the need for new facilities and in the design and
construction of such facilities.'' The transmission provider's
obligation to upgrade or expand its system to provide point-to-point
service as detailed in section 15.4 is contingent on the transmission
customer agreeing to compensate the transmission provider for such
costs pursuant to the terms of section 27 (providing for cost
responsibility for upgrades and/or redispatch ``to the extent
consistent with Commission policy'').
    420. In Order No. 888-A, the Commission encouraged utilities to
engage in joint planning with other utilities and customers and to
allow affected customers to participate in facilities studies to the
extent practicable. The Commission also encouraged regional planning so
that the needs of all participants are represented in the planning
process.\225\ Order No. 888-A did not, however, require that
transmission providers coordinate with either their network or point-
to-point customers in transmission planning or otherwise publish the
criteria, assumptions, or data underlying their transmission plans. The
Commission also did not require joint planning between transmission
providers and their customers or between transmission providers in a
given region.\226\ The only section of the existing pro forma OATT that
directly speaks to joint planning is section 30.9, which provides that
a network customer must receive credit when facilities constructed by
the customer are jointly planned and installed in coordination with the
transmission provider.\227\
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    \225\ See Order No. 888-A at 30,311.
    \226\ See id.
    \227\ Pro forma OATT section 21.2, ``Coordination of Third-Party
System Additions,'' provides for certain rights for transmission
providers to coordinate construction of facilities on their systems
associated with point-to-point customer requests and related
construction on a third-party transmission system, but imposes no
obligation on transmission providers.

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    421. As the Commission stated in the NOPR, the Nation has witnessed
a decline in transmission investment relative to load growth in the ten
years since Order No. 888 was issued. Transmission capacity per MW of
peak demand has declined in every NERC region. Transmission constraints
plague most regions of the country, as reflected in the limited amounts
of ATC posted in many regions, increased frequency of denied
transmission requests, increasingly common transmission service
interruptions or curtailments and rising congestion costs in organized
markets.\228\
---------------------------------------------------------------------------

    \228\ The number of TLRs has increased significantly since NERC
started reporting annual statistics. The total number of TLRs each
year has grown from under 500 in 1998 and 1999 to around 2000 over
the last four years from 2002 to 2006. The number of TLR actions at
the highest levels, requiring curtailment of firm transmission
flows, has also grown, from under 10 before 2001 to 70 in 2006,
averaging 55 per year from 2003 to 2006. Source: NERC Web site,
ftp://www.nerc.com/pub/sys/all_updl/oc/scs/logs/trends.htm. In

addition, congestion costs continue to be a major issue in RTO
markets. For example, congestion costs in PJM were $2.09 billion in
calendar year 2005, which was a 179 percent increase over 2004.
Although this increase resulted primarily from increases in PJM
annual billings, the congestion costs in both years were
approximately 9 percent of total PJM billings in both years and have
ranged from 6 percent to 10 percent of total billings since 2000.
Source: 2005 PJM State of the Markets Report, April 2006.
---------------------------------------------------------------------------

    422. We do not believe that the existing pro forma OATT is
sufficient in an era of increasing transmission congestion and the need
for significant new transmission investment. We cannot rely on the
self-interest of transmission providers to expand the grid in a
nondiscriminatory manner. Although many transmission providers have an
incentive to expand the grid to meet their State-imposed obligations to
serve, they can have a disincentive to remedy transmission congestion
when doing so reduces the value of their generation or otherwise
stimulates new entry or greater competition in their area. For example,
a transmission provider does not have an incentive to relieve local
congestion that restricts the output of a competing merchant generator
if doing so will make the transmission provider's own generation less
competitive. A transmission provider also does not have an incentive to
increase the import or export capacity of its transmission system if
doing so would allow cheaper power to displace its higher cost
generation or otherwise make new entry more profitable by facilitating
exports.
    423. As the Commission explained in Order No. 888, ``[i]t is in the
economic self-interest of transmission monopolists, particularly those
with high-cost generation assets, to deny transmission or to offer
transmission on a basis that is inferior to that which they provide
themselves.'' \229\ The court agreed on review of Order No. 888, noting
in TAPS v. FERC that ``[u]tilities that own or control transmission
facilities naturally wish to maximize profit. The transmission-owning
utilities thus can be expected to act in their own interest to maintain
their monopoly and to use that position to retain or expand the market
share for their own generated electricity, even if they do so at the
expense of lower-cost generation companies and consumers.'' \230\ The
Supreme Court in New York v. FERC similarly explained that ``public
utilities retain ownership of the transmission lines that must be used
by their competitors to deliver electric energy to wholesale and retail
customers. The utilities' control of transmission facilities gives them
the power either to refuse to deliver energy produced by competitors or
to deliver competitors' power on terms and conditions less favorable
than those they apply to their own transmissions.'' \231\
---------------------------------------------------------------------------

    \229\ Order No. 888 at 31,682.
    \230\ 225 F.3d at 684.
    \231\ 535 U.S. at 8-9 (citation and footnotes omitted).
---------------------------------------------------------------------------

    424. The existing pro forma OATT does not counteract these
incentives in the planning area because there are no clear criteria
regarding the transmission provider's planning obligation. Although the
pro forma OATT contains a general obligation to plan for the needs of
their network customers and to expand their systems to provide service
to point-to-point customers, there is no requirement that the overall
transmission planning process be open to customers, competitors, and
State commissions.\232\ Rather, transmission providers may develop
transmission plans with limited or no input from customers or other
stakeholders. There also is no requirement that the key assumptions and
data that underlie transmission plans be made available to customers.
---------------------------------------------------------------------------

    \232\ As discussed in more detail in the NOPR, the need for
reform was recognized by the Consumer Energy Council of America
(CECA), a public interest energy policy organization with a 30-year
history of bringing stakeholders together to find solutions to
contentious energy policy issues. CECA launched its Transmission
Infrastructure Forum in early 2004, which published its conclusions
in January 2005 in a final report titled ``Keeping the Power
Flowing: Ensuring a Strong Transmission System to Support Consumer
Needs for Cost-Effectiveness, Security and Reliability'' (CECA
Report). Among other things, the CECA Report concludes that regional
transmission planning with consumer input early in the process is
needed to ensure the development of a robust transmission system
capable of meeting consumer needs reliably and at reasonable cost
over time. The CECA Report stresses that regional transmission
planning must address inter-regional coordination, the need for both
reliability and economic upgrades to the system, and critical
infrastructure to support national security and environmental
concerns. See NOPR at P 207.
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    425. Taken together, this lack of coordination, openness, and
transparency results in opportunities for undue discrimination in
transmission planning. Without adequate coordination and open
participation, market participants have no means to determine whether
the plan developed by the transmission provider in isolation is unduly
discriminatory. This means that disputes over access and discrimination
occur primarily after-the-fact because there is insufficient
coordination and transparency between transmission providers and their
customers for purposes of planning.\233\ The Commission has a duty to
prevent undue discrimination in the rates, terms, and conditions of
public utility transmission service and, therefore, an obligation to
remedy these transmission planning deficiencies. As we explain above,
our authority to remedy undue discrimination is broad.\234\ In
addition, new section 217 of the FPA requires the Commission to
exercise its jurisdiction in a manner that facilitates the planning and
expansion of transmission facilities to meet the reasonable needs of
LSEs. A more transparent and coordinated regional planning process will
further these priorities, as well as support the DOE's responsibilities
under EPAct 2005 section 1221 to study transmission congestion and
issue reports designating National Interest Electric Transmission
Corridors and the Commission's responsibilities under EPAct 2005
section 1223.
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    \233\ In our discussion of enforcement issues at section V.E of
this Final Rule, we note specific situations in which transmission
providers have agreed to resolve staff allegations that they engaged
in OATT violations involving transactions with affiliates. While
these specific situations may not directly relate to discrimination
in planning, they nevertheless document the continuing incentive of
transmission providers to favor themselves and their affiliates in
the provision of transmission service.
    \234\ See Order No. 888 at 31,669 (noting that the FPA ``fairly
bristles'' with concern for undue discrimination (citing AGD, 824
F.2d at 998).
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NOPR Proposal
    426. In order to provide for more comparable open access
transmission service, limit the potential for undue discrimination and
anticompetitive conduct, and satisfy its statutory responsibilities
under section 217 of the FPA, the Commission proposed to amend the pro
forma OATT to require coordinated, open, and transparent transmission
planning on both a local and regional level. Each public utility

transmission provider would be required to submit, as part of its
compliance filing in this proceeding, a proposal for a coordinated and
regional planning process that complies with the following eight
planning principles: Coordination, openness, transparency, information
exchange, comparability, dispute resolution, regional participation,
and congestion studies. In the alternative, transmission providers
could make a compliance filing in this proceeding describing their
existing coordinated and regional planning processes and showing that
they are consistent with or superior to that required in the Final
Rule.
    427. The Commission stated that it expected non-public utility
transmission providers to participate in the proposed planning
processes, given that effective regional planning cannot occur without
the participation of all transmission providers, owners, and customers.
Although the Commission encouraged the use of an independent third
party to oversee or coordinate the planning process, the NOPR did not
propose to require it. The Commission also strongly encouraged the
participation of State commissions and other State agencies in planning
activities.
    428. The Commission sought comment on several aspects of the NOPR
proposal. First, the Commission inquired as to the level of flexibility
each transmission provider should be given in implementing any
principles adopted. Second, the Commission sought comment, by way of
example, on transmission planning processes that comply with the NOPR
reforms in principle. Third, the Commission sought comment on whether
there are other principles or requirements that should be adopted to
support the construction of needed new infrastructure and otherwise
ensure that all market participants are treated on a comparable basis.
Specifically, the Commission inquired: (a) Whether there should be a
principle or guideline to govern the recovery and allocation of costs
associated with funding the regional planning requirement; (b) whether
there should be a requirement that, at least for large new transmission
projects, there be an open season to allow market participants to
participate in joint ownership of these projects; (c) whether there
should be a specific study process to identify opportunities to enhance
the grid for purposes beyond maintaining reliability or reducing
current congestion; and, (d) whether public utilities should be
required to develop cost allocation principles to address the sharing
of the costs of new transmission projects and, given that such projects
can take years to construct, whether the planning process should be
required to look out at least as far as the longest time it would take
to build such an upgrade in the region in question. Finally, the
Commission sought comment on the level of detail to be required in
transmission providers' OATTs.
Comments
    429. Most commenters support the development of coordinated, open,
and transparent planning. While differing on how they should be
implemented, commenters express broad support for the eight planning
principles,\235\ though all RTOs and ISOs and many investor-owned
utilities believe that their planning processes already comply with the
proposals in the NOPR. ISO/RTO Council, as well as individual RTOs and
ISOs, advance the position that RTOs and ISOs already meet the planning
requirements in the NOPR, that there has been no credible case made for
reopening their already approved planning processes, and that RTOs and
ISOs should be exempt from complying with the NOPR's planning
principles.
---------------------------------------------------------------------------

    \235\ The one exception is the congestion studies requirement,
which is generally opposed by transmission providers and supported
by customers.
---------------------------------------------------------------------------

    430. Some transmission providers agree that RTOs already meet the
principles, and others argue against commenters who maintain that RTOs
``rubber stamp'' transmission provider plans.\236\ For example, MISO
asserts that it conducts an open planning process and does not ``rubber
stamp'' projects. Duke concurs with MISO, stating that there are
abundant opportunities for participation in the MISO planning process.
Xcel also replies in support of the MISO process.
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    \236\ E.g., Duke, Exelon, and Xcel.
---------------------------------------------------------------------------

    431. Several transmission customers, however, argue that current
RTO processes are insufficient because, among other things, they merely
accept the transmission owners' plans and only provide for after-the-
fact input, thus failing to satisfy the planning principles proposed in
the NOPR.\237\ Old Dominion also asserts that RTOs generally approve
transmission owner identified upgrades, which give them the advantage
of having their own parochial plans incorporated into the regional plan
without any separate evaluation or complete stakeholder input. TAPS
asserts that open planning should apply both to the RTO and the
underlying transmission owners' planning efforts. In its reply, WPS
opposes MISO's proposal to be exempt from the NOPR's planning
requirements, arguing that the MISO process is not open and only
aggregates the plans of the transmission providers.
---------------------------------------------------------------------------

    \237\ E.g., Indicated Parties Reply, Old Dominion, NRECA, and
TAPS.
---------------------------------------------------------------------------

    432. EEI takes issue with broad statements in the NOPR that assert
that transmission providers have a disincentive to remedy transmission
congestion and to plan their transmission systems on a comparable
basis. Other individual investor-owned utilities also assert that the
record does not support the NOPR's claims that a mandatory coordinated,
open, and transparent planning process is necessary to remedy undue
discrimination.\238\ Many others, however, believe the NOPR correctly
diagnoses the problem of discrimination.\239\
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    \238\ See, e.g., Duke and Southern.
    \239\ See, e.g., APPA and EPSA. However, NRG and Reliant believe
that the planning process outside of RTOs is fundamentally flawed
and cannot be remedied by the NOPR's planning proposal.
---------------------------------------------------------------------------

    433. Most commenters do not question the Commission's jurisdiction
to address the transmission planning process generally. Southern,
however, argues that the Commission has no general authority in this
area and that section 217 of the FPA does not grant the Commission any
additional jurisdiction to impose a regional planning requirement.\240\
FMPA counters that the Commission has FPA authority to cure undue
discrimination and to ensure ``just and reasonable'' transmission rates
and terms by adopting transmission planning criteria.\241\ In their
replies, APPA and TAPS agree with the Commission that FPA section
217(b)(4) can be cited as legal support for transmission planning. In
its reply, NRECA stresses that the transmission planning process must
focus, consistent with FPA section 217(b)(4), on the reasonable long-
term needs of LSEs, not all users of the system as argued by EPSA and
NRG. Santee Cooper urges the Commission to be mindful of the limits of
its jurisdiction in establishing study requirements that may delve into
generation resource adequacy or issues related to the mix of
generation. Other commenters urge the Commission not to impinge on
State jurisdiction.\242\ In its reply, LPPC emphasizes that the
Commission's expectation that public power entities will participate is

sufficient and asserts that there is no reason to take further action
that might test the limits of jurisdiction under FPA section 211A.\243\
---------------------------------------------------------------------------

    \240\ Progress Energy also claims that the Commission does not
have any jurisdiction to mandate regional planning.
    \241\ See also TAPS Reply.
    \242\ See, e.g., Nevada Companies, New Mexico Attorney General,
North Carolina Commission Reply, and Southern.
    \243\ Other jurisdictional arguments primarily relate to the
question of joint ownership, in which some commenters argue that the
Commission lacks jurisdiction to mandate joint ownership
arrangements. See, e.g., Duke, EEI, National Grid, Northeast
Utilities, PSEG, and Southern. FMPA and others, however, argue that
the Commission does have the authority to order joint ownership.
Joint ownership will be discussed more fully below.
---------------------------------------------------------------------------

    434. WIRES endorses several planning objectives it believes to be
critical to successful planning. These objectives include open and
transparent planning procedures, a long-term planning horizon, broad-
based inclusion of reliability, economic, efficiency and environmental
considerations in planning, clear conditions under which a transmission
owner will commit to build planned facilities, and provision for fair
and efficient allocation of the costs of planned facilities. WIRES also
emphasizes the importance of considering non-transmission alternatives,
arguing that an appropriate grid plan must be based on an integrated
view of all alternatives, including demand response and distributed
generation.
Commission Determination
    435. In order to limit the opportunities for undue discrimination
described above and in the NOPR, and to ensure that comparable
transmission service is provided by all public utility transmission
providers, including RTOs and ISOs, the Commission concludes that it is
necessary to amend the existing pro forma OATT to require coordinated,
open, and transparent transmission planning on both a local and
regional level. We disagree with commenters arguing either that we lack
jurisdiction to require coordinated transmission planning or that we
have not established a basis for such a requirement. The Commission has
broad authority to remedy undue discrimination by ensuring that
transmission providers plan for the needs of their customers on a
comparable basis.\244\ That fundamental requirement was adopted in
Order No. 888 and the reforms adopted herein should ensure that it will
be implemented properly. Further, we explained in detail above why
undue discrimination remains a concern in the planning area and why the
existing OATT is insufficient to address that concern.
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    \244\ See AGD, 824 F.2d at 1008 (Commission has broad discretion
to promulgate generic rules to eliminate undue discrimination
without ``conduct[ing] experiments in order to rely on the
prediction that an unsupported stone will fall'').
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    436. New section 217 of the FPA further supports reform in this
area, as it reflects Congress' intent that the Commission utilize its
powers to facilitate the planning and expansion of the transmission
system.\245\ Through EPAct 2005 sec. 1223, Congress also directed the
Commission to encourage the deployment of advanced transmission
technologies in infrastructure improvements, including among others
optimized transmission line configurations (including multiple phased
transmission lines), controllable load, distributed generation
(including PV, fuel cells, and microturbines), and enhanced power
device monitoring.
---------------------------------------------------------------------------

    \245\ FPA section 217(b)(4) provides that ``[t]he Commission
shall exercise the authority of the Commission under [the FPA] in a
manner that facilitates the planning and expansion of transmission
facilities to meet the reasonable needs of load-serving entities to
satisfy the service obligations of the load-serving entities, and
enables load-serving entities to secure firm transmission rights (or
equivalent tradable or financial rights) on a long term basis for
long term power supply arrangements made, or planned, to meet such
needs.''
---------------------------------------------------------------------------

    437. Accordingly, each public utility transmission provider is
required to submit, as part of a compliance filing in this proceeding,
a proposal for a coordinated and regional planning process that
complies with the planning principles and other requirements in this
Final Rule.\246\ In the alternative, a transmission provider (including
an RTO or an ISO, as discussed below), may make a compliance filing in
this proceeding describing its existing coordinated and regional
planning process, including the appropriate language in its tariff, and
show that this existing process is consistent with or superior to the
requirements in this Final Rule. Under either of these approaches, the
process must be documented as an attachment to the transmission
provider's OATT.
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    \246\ The pro forma OATT, as modified by this Final Rule,
reflects the proposed planning requirement in sections 15.4, 16.1,
17.2(x), 28.2, 29.2, 31.6. The planning process itself will be
included as Attachment K to the pro forma OATT. We understand that
some transmission providers may already have attachments to their
OATTs labeled with the letter ``K,'' in which case transmission
providers are free to label their planning process OATT attachment
with the next available letter.
---------------------------------------------------------------------------

    438. At the outset, we note that the planning obligations imposed
in this Final Rule do not address or dictate which investments
identified in a transmission plan should be undertaken by transmission
providers. Furthermore, except for the discussion below of cost
allocation for transmission investments under Principle 9, the planning
obligations included in this Final Rule do not address whether or how
investments identified in a transmission plan should be compensated.
Through the principles described below, we establish a process through
which transmission providers must coordinate with customers,
neighboring transmission providers, affected State authorities, and
other stakeholders in order to ensure that transmission plans are not
developed in an unduly discriminatory manner.
    439. As for the application of the Final Rule's coordinated
planning requirement to RTOs and ISOs, which already have a Commission-
approved transmission planning process on file with us, we note that
the intent of our reform in this Final Rule is not to reopen prior
approvals, but rather to ensure that the transmission planning process
utilized by each RTO and ISO is consistent with or superior to the
planning process adopted here. When the Commission approved the
existing RTO and ISO transmission planning processes, they were found
to be consistent with or superior to the existing pro forma OATT.
Because the pro forma OATT is being reformed by this Final Rule, it is
necessary for each RTO and ISO to now either reform its process or show
that its planning process is consistent with or superior to the pro
forma OATT, as modified by the Final Rule.
    440. We also make clear that transmission owning members of ISOs
and RTOs must participate in the planning processes adopted in this
Final Rule. In order for an RTO's or ISO's planning process to be open
and transparent, transmission customers and stakeholders must be able
to participate in each underlying transmission owner's planning
process. This is important because, in many cases, RTO planning
processes may focus principally on regional problems and solutions, not
local planning issues that may be addressed by individual transmission
owners. These local planning issues, however, may be critically
important to transmission customers, such as those embedded within the
service areas of individual transmission owners. Consequently, the
intent of the Final Rule will not be realized if only the regional
planning process conducted by the RTOs and ISOs is shown to be
consistent with or superior to the Final Rule. To ensure full
compliance, individual transmission owners must, to the extent that
they perform transmission planning within an RTO or ISO, comply with
the Final Rule as well. Without such a requirement, the more regional
RTO or

ISO planning process will not comply with the requirements of the Final
Rule to the extent they incorporate and rely on information prepared by
underlying transmission owners that, in turn, have not complied with
the Final Rule. Accordingly, as part of their compliance filings in
this proceeding, RTOs and ISOs must indicate how all participating
transmission owners within their footprint will comply with the
planning requirements of this Final Rule. While we leave the mechanics
of such compliance to each RTO and ISO, we emphasize that the RTO's or
ISO's planning processes will be insufficient if its underlying
transmission owners are not also obligated to engage in transmission
planning that complies with Final Rule.\247\
---------------------------------------------------------------------------

    \247\ We understand that there are some transmission owners in
RTOs or ISOs that continue to have OATTs on file under which they
provide service over certain transmission facilities that they did
not turn over to the operational control of the RTO or ISO. Like any
other transmission provider, those entities must submit a compliance
filing to their OATTs that satisfies all requirements of this Final
Rule, including the inclusion of an attachment governing their own
planning procedures. As we explain elsewhere, the compliance filing
deadline for transmission owning participants in RTOs and ISOs shall
be the same as the RTO and ISO deadline, i.e., 210 days after
publication of the Final Rule in the Federal Register.
---------------------------------------------------------------------------

    441. The Commission also expects all non-public utility
transmission providers to participate in the planning processes
required by this Final Rule. A coordinated, open, and transparent
regional planning process cannot succeed unless all transmission owners
participate. We are encouraged, based on the representations of LPPC
and others, that non-public utility transmission providers will fully
participate in such processes. We therefore do not believe it is
necessary at this time to invoke our authority under FPA section 211A,
which gives us authority to require non-public utility transmission
providers to provide transmission services on a comparable and not
unduly discriminatory or preferential basis.\248\ If we find on the
appropriate record, however, that non-public utility transmission
providers are not participating in the planning processes required by
this Final Rule, the Commission may exercise its authority under
section 211A on a case-by-case basis. Further, we note that reciprocity
dictates that non-public utility transmission providers that take
advantage of open access due to improved planning should be subject to
the same requirements as jurisdictional transmission providers.
---------------------------------------------------------------------------

    \248\ FPA section 211A(b) provides, in pertinent part, that
``the Commission may, by rule or order, require an unregulated
transmitting utility to provide transmission services--(1) At rates
that are comparable to those that the unregulated transmitting
utility charges itself; and (2) on terms and conditions (not
relating to rates) that are comparable to those under which the
unregulated transmitting utility provides transmission services to
itself and that are not unduly discriminatory or preferential.'' The
non-public utility transmission providers referred to in this Final
Rule include unregulated transmitting utilities that are subject to
FPA section 211A.
---------------------------------------------------------------------------

    442. In sum, each OATT planning process attachment must incorporate
the transmission planning principles and concepts in this Final Rule
and must be filed with the Commission within 210 days after the
publication of the Final Rule in the Federal Register. Alternatively,
RTOs, ISOs, and other transmission providers that currently have
planning processes they believe comply with the Final Rule may make a
filing with the Commission documenting those processes in an OATT
attachment and explaining how their planning processes are consistent
with or superior to the planning process adopted here. Such filings
must also be submitted within 210 days after the publication of the
Final Rule in the Federal Register.
    443. In order to assist transmission providers in complying with
the Final Rule, and ensure that the planning procedures are developed
with customer and stakeholder participation, the Commission will
convene staff technical conferences in several broad regions around the
country to discuss regional implementation and other compliance issues
in advance of the compliance date. We extend an invitation to State
regulatory commissions to participate in these technical conferences
with our staff in order to ensure that State concerns are fully
addressed. The Commission will endeavor to hold the technical
conferences 90 to 120 days after the publication of the Final Rule in
the Federal Register. To facilitate these conferences, each
transmission provider should, within 75 days after the publication of
the Final Rule in the Federal Register, post a ``strawman'' proposal
for compliance with each of the planning principles adopted in the
Final Rule, including a specification of the broader region in which it
will conduct coordinated regional planning. This strawman may be posted
on the transmission provider's OASIS, or its Web site if it does not
have its own OASIS (e.g., in the case of a transmission owning member
of an RTO or ISO that does not have its own OATT). We strongly urge
transmission providers to consult with their stakeholders in the
development of this strawman.
2. Planning Principles
    444. We set forth below the planning principles that must be
satisfied for a transmission provider's planning process to be
considered compliant with the Final Rule. The NOPR identified eight
such principles, but based on the comments received the Commission will
require compliance with nine--the original eight plus a cost allocation
principle, as described further below.
a. Coordination
    445. In the NOPR, the Commission proposed that transmission
providers must meet with all of their transmission customers and
interconnected neighbors to develop a transmission plan on a
nondiscriminatory basis. We sought comment on specific requirements for
this coordination, such as the minimum number of meetings to be
required each year, the scope of the meetings, the notice requirements,
the format, and any other features deemed important by commenters.
Comments
    446. Commenters express universal support for the general concept
of coordination, but differ on how specific the requirement should be.
Several commenters argue that the requirement that transmission
providers ``must meet'' with customers and utilities is
unrealistic.\249\ EEI requests that the Commission clarify that
transmission providers will be responsible for coordinating with
customers and holding meetings, but that the requirement to meet should
be limited to making reasonable efforts to meet with all customers.
NRECA asks on reply that the Commission make clear that the lack of
full participation by some nonjurisdictional utilities that take
network service under the OATT should not excuse the transmission
provider's obligation to engage in transmission planning. NRECA states
that inclusion in the planning process must be an opportunity for LSEs,
not an obligation.
---------------------------------------------------------------------------

    \249\ E.g., Allegheny, Duke, EEI, International Transmission,
MidAmerican, NorthWestern, and SCE.
---------------------------------------------------------------------------

    447. Other commenters express a more general concern that the
Commission not be prescriptive with respect to meeting
requirements.\250\ For example, most commenters generally believe the
Commission should not prescribe rigid rules regarding the number of
meetings that must be held

each year. Xcel, however, suggests that a minimum of three meetings a
year would be appropriate. Progress notes that coordination in North
Carolina already occurs as a result of regular meetings throughout the
year. Nevada Companies believe that meetings should be dependent on
need and should not be programmatically established. TDU Systems
recommend at least monthly meetings, but stress that meetings should be
as frequent as is required to specify and perform the studies forming
the basis for the plan. NCPA believes that the minimum requirements are
not as important as how they can be monitored or enforced to ensure
that true participation indeed occurs.
---------------------------------------------------------------------------

    \250\ E.g., Allegheny, APPA, Bonneville, California Commission,
Duke, Entergy, Imperial, International Transmission, MidAmerican,
NCEMC, NC Transmission Planning Participants Reply, NorthWestern,
NRECA, Pinnacle, Progress Energy, CREPC, Santee Cooper, SCE, TVA,
and WAPA.
---------------------------------------------------------------------------

    448. Seattle suggests 30 days notice for meetings and that
information regarding meetings be posted at least one week in advance.
Entergy finds a notice requirement reasonable, and other utilities
suggest a 30-day requirement would be appropriate.\251\ Seattle also
suggests e-mail notification and Salt River supports internet posting.
With respect to details beyond frequency and notice, Entergy cautions
the Commission against being too prescriptive.
---------------------------------------------------------------------------

    \251\ E.g., Nevada Companies and NorthWestern.
---------------------------------------------------------------------------

    449. On meeting scope, several commenters request that the
Commission make clear that the purpose of the meeting is to focus on
transmission issues and not provide a broad forum for other
issues.\252\ Sacramento believes that meetings should be limited to
sub-regional or regional transmission planning and not include planning
to meet local transmission needs.
---------------------------------------------------------------------------

    \252\ E.g., Entergy, Progress Energy, SCE, and Southern.
---------------------------------------------------------------------------

    450. Other commenters stress that joint planning requires more than
just meeting with customers and that all LSEs need to be integrated
into the planning process so that they are actively developing
transmission plans alongside transmission providers from the
inception.\253\ This concept of collaborative planning is a running
theme in the comments provided by several public power entities, such
as NRECA, TAPS, and TDU Systems. TDU Systems argue that comparability
requires that LSEs have equal weight in decision-making rather than
provide de facto veto authority to transmission providers. NRECA argues
in its reply that collaborative planning is required by FPA section
217(b)(4). These commenters assert that LSEs must be able to
participate in the development of planning models, including the
assumptions and criteria that go into these models, and in the
development of the base case and change case for study purposes,
particularly as to the identification and projection of loads and
resources.\254\ Progress and Southern, however, argue in replies that
giving customers equal weight in decision-making crosses the line from
planning to control by third parties, and Southern believes this would
be opposed by State regulators.
---------------------------------------------------------------------------

    \253\ E.g., NRECA, Seminole Reply, TAPS, and TDU Systems.
    \254\ This collaborative approach is also generally supported by
East Texas Cooperatives, FMPA, NCEMC, NCPA, and Old Dominion. NCEMC
believes that the key to ensuring true collaboration is a voting
structure, like that adopted in the North Carolina Transmission
Planning Collaborative, which gives all load-serving entities an
equal say in planning decisions. APPA also believes that giving
customers a say in the outcome (e.g., through voting) is critical.
---------------------------------------------------------------------------

Commission Determination
    451. The Commission adopts the coordination principle proposed in
the NOPR. Commenters overwhelmingly desire flexibility as to the
coordination principle, and as such, we will not prescribe the
requirements for coordination, such as the minimum number of meetings
to be required each year, the scope of the meetings, the notice
requirements, the format, and any other features. We will allow
transmission providers, with the input of their customers and other
stakeholders, to craft coordination requirements that work for those
transmission providers and their customers and other stakeholders.
    452. We emphasize that the purpose of the coordination requirement
is to eliminate the potential for undue discrimination in planning by
opening appropriate lines of communication between transmission
providers, their transmission-providing neighbors, affected State
authorities, customers, and other stakeholders. Rigid and formal
meeting procedures may be one way to accomplish this goal, but there
may be other ways as well. For example, a transmission provider could
meet this requirement by facilitating the formation of a permanent
planning committee made up of itself, its neighboring transmission
providers, affected State authorities, customers, and other
stakeholders. Such a planning committee could develop its own means of
communication, which may or may not emphasize formal meeting
procedures. We are more concerned with the substance of coordination
than its form.
    453. In response to the concerns of some commenters, we clarify
that transmission providers are not required to meet with customers and
other stakeholders that choose not to meet. Transmission providers
cannot force others to meet with them. Transmission providers are,
however, required to craft a process that allows for a reasonable and
meaningful opportunity to meet or otherwise interact meaningfully. We
also clarify that the coordination requirements imposed in this Final
Rule are intended to address transmission planning issues, and are not
intended to provide a forum for ancillary issues, such as specific
siting concerns, which are better addressed elsewhere. As for NRECA's
concern that transmission providers must plan for their
nonjurisdictional network customers even if they decline to fully
participate in the planning process, a transmission provider cannot be
expected to effectively plan for a customer if that customer declines
to engage in the planning process. Therefore, we encourage NRECA and
non-public utilities to participate fully in the planning process.
    454. In response to the suggestion by some commenters that we
require transmission providers to allow customers to collaboratively
develop transmission plans with transmission providers on a co-equal
basis, we clarify that transmission planning is the tariff obligation
of each transmission provider, and the pro forma OATT planning process
adopted in this Final Rule is the means to see that it is carried out
in a coordinated, open, and transparent manner, in order to ensure that
customers are treated comparably. Therefore, the ultimate
responsibility for planning remains with transmission providers. With
this said, we fully intend that the planning process adopted herein
provide for the timely and meaningful input and participation of
customers into the development of transmission plans. This means that
customers must be included at the early stages of the development of
the transmission plan and not merely given an opportunity to comment on
transmission plans that were developed in the first instance without
their input.
b. Openness
    455. In the NOPR, the Commission proposed that transmission
planning meetings must be open to all affected parties (including all
transmission and interconnection customers and State authorities). The
Commission also sought comment on whether there are any circumstances
under which participation should be limited, for example, to address
confidentiality concerns.

Comments
    456. Commenters generally agree on the need to meet with all
affected parties, as well as the need to limit some meetings for
security or confidentiality reasons. Certain commenters urge the
Commission to make clear that openness does not extend to a requirement
to meet with the general public and that the meetings are for
``industry and governmental representatives'' only.\255\ For example,
Southern agrees that eligible transmission customers and State
commissions should be allowed to participate in the meetings, but
states that these meetings should not be open to the general public to
help ensure that the focus is on core transmission planning and not be
diverted to other issues.
---------------------------------------------------------------------------

    \255\ E.g., APPA, EEI, Salt River, and Southern.
---------------------------------------------------------------------------

    457. Transmission providers generally note that some meetings will
need to be limited for CEII concerns or for discussion of commercially-
sensitive information.\256\ Progress Energy states the Commission
should be flexible regarding the composition of meetings and openness,
noting that in North Carolina meetings involving CEII are limited to
transmission personnel and non-marketing personnel of participating
LSEs, while other meetings in the North Carolina process are open to
the public. In their reply, NC Transmission Planning Participants note
that they have been able to negotiate confidentiality protocols
agreeable to each of them. Duke believes that restrictions on open
meetings need to be in place when sensitive commercial information is
being discussed, so that personnel engaged in the merchant function do
not gain access to sensitive information about their competitors.
Indianapolis Power recommends the Commission keep existing restrictions
on access to planning meetings in place to preserve current protections
on security and competitive information. TVA states that it is
particularly concerned with maintaining confidentially and asks the
Commission to defer to NERC and its Regional Entities, which TVA says
are developing procedures for planning.
---------------------------------------------------------------------------

    \256\ Other commenters also recognize the need to maintain
confidentiality for CEII and commercially-sensitive information.
E.g., Arkansas Commission, AWEA, California Commission, NCPA, NRECA,
CREPC, Seattle, TDU Systems, and WAPA.
---------------------------------------------------------------------------

    458. Commenters also raise issues regarding the application of the
Commission's Standards of Conduct to those that participate in planning
meetings.\257\ EEI, for example, believes that if information is
disclosed during a planning meeting and is not simultaneously made
public, then all planning participants--including nonjurisdictional
entities--should be subject to the Commission's Standards of Conduct.
APPA understands the need to ensure that non-public information
obtained during planning meetings is not utilized to gain an unfair
advantage in the power market; however, it believes that other means
short of the application of the Standards of Conduct would suffice,
such as requiring simultaneous disclosure of information as a ``safe
harbor'' or the use of confidentiality agreements.\258\
    459. NRECA and TDU Systems argue that meetings should be open and,
joined by APPA, suggest that confidentiality issues can be managed with
confidentiality agreements and other arrangements (such as password
protected access to information). TAPS suggests that access to data be
limited to transmission dependent utility employees not involved in
marketing or to an outside consultant. California Commission stresses
that any advisory subcommittees must also be open to all stakeholders.
---------------------------------------------------------------------------

    \257\ Commenters raise issues with regard to the application of
the Commission's Standards of Conduct to planning participants in
their comments addressing some of the other principles as well,
which will be discussed below, as well as addressed in the pending
rulemaking in Docket No. RM07-1-000. See Standards of Conduct NOPR.
    \258\ See also East Texas Cooperatives Reply and NRECA Reply.
---------------------------------------------------------------------------

Commission Determination
    460. The Commission adopts the NOPR's proposal and will require
that transmission planning meetings be open to all affected parties
including, but not limited to, all transmission and interconnection
customers, State commissions and other stakeholders. We recognize that
it may be appropriate in certain circumstances, such as a particular
meeting of a subregional group, to limit participation to a relevant
subset of these entities. We emphasize, however, that the overall
development of the transmission plan and the planning process must
remain open. We agree with the concerns of some commenters that
safeguards must be put in place to ensure that confidentiality and CEII
concerns are adequately addressed in transmission planning activities.
Accordingly, we will require that transmission providers, in
consultation with affected parties, develop mechanisms, such as
confidentiality agreements and password-protected access to
information, in order to manage confidentiality and CEII concerns.
Lastly, concerns surrounding the application of the Commission's
Standards of Conduct to planning participants, and whether and how
these standards should affect access to and use of information obtained
in the planning process, will be discussed below.
c. Transparency
    461. In the NOPR, the Commission proposed that transmission
providers be required to disclose to all customers and other
stakeholders the basic criteria, assumptions, and data that underlie
their transmission system plans. The Commission also sought comment on
whether the information provided in FERC Form 715 (Form 715) is
adequate and, if not, what additional detail should be provided. In
addition, the Commission sought comment on the format for disclosure,
including protections to address confidentiality concerns.
Comments
    462. Transmission providers generally agree that they should
provide the basic criteria, assumptions, and data for planning, but
argue that non-public utility transmission providers should also be
required to provide comparable information.\259\ In general, EEI
believes that information provided during the planning process should
be treated as confidential and not disclosed to the general public.
---------------------------------------------------------------------------

    \259\ E.g., CAISO, EEI, and SCE.
---------------------------------------------------------------------------

    463. Public power entities and other commenters support
transparency and also are sensitive to confidentiality concerns.\260\
NCPA believes that the failure of CAISO to release planning data is one
of the biggest failings of CAISO planning process. Without access to
criteria, assumptions, and data inputs, NCPA argues that customers
cannot duplicate planning results, nor can they independently determine
whether the assumptions are correct, whether the model is producing the
right results, whether those results are being fairly applied in the
choice of projects to be undertaken, or assess the impacts on their own
customers. APPA suggests that transmission providers be required to
reduce to writing the methodology, criteria, and processes they use to
develop their transmission plans, including how they treat retail
native loads, in order to ensure that standards are consistently
applied.

CREPC points out that transparency is necessary if State regulatory
processes are to give deference to planning results. Sacramento asserts
that it may be reasonable to allow customers and stakeholders access to
the planning model or at least allow access to a comprehensive
description of the model and methodology, in order to allow others to
closely replicate the planning analysis. Sacramento is joined by
Imperial in referencing WECC's on-going effort to increase planning
transparency.
---------------------------------------------------------------------------

    \260\ E.g., APPA, California Commission, NCPA, CREPC, Salt
River, and WAPA. Old Dominion, however, does not believe that any of
the data required to be disclosed is commercially-sensitive;
however, it does recognize that it may be CEII, in which case it
claims security can be maintained via a secure OASIS site.
---------------------------------------------------------------------------

    464. NRECA and TDU Systems, however, do not believe that a specific
disclosure principle would be necessary if LSEs were truly integrated
into the planning process. In other words, they argue that if the
process is truly open, then LSEs, as participants in the development of
the joint plan, should already have access to the inputs and
assumptions underlying the plans and, in fact, should have helped
develop them.
    465. EEI believes that Standards of Conduct requirements should be
placed on all participants in the planning process whenever disclosure
of commercially-sensitive information is needed for planning. East
Texas Cooperatives argues that the Standards of Conduct should not be
generically applied to public power and that such issues should be
managed with confidentiality agreements and case-by-case protective
orders. In its reply, NRECA also asserts that, while it is necessary to
protect competitively-sensitive information, there is no basis for
requiring nonjurisdictional entities to comply with the formal
separation of functions requirements simply because they have received
information in the planning process, as this is inconsistent with the
cooperative utility business model. Rather, NRECA believes
commercially-sensitive information can be handled in other established
ways. APPA also suggests that Standards of Conduct issues can be
managed by providing for certain ``safe harbors'' for participation,
such as simultaneous disclosure of information or the use of an
independent facilitator.\261\
---------------------------------------------------------------------------

    \261\ NARUC asks the Commission to re-examine the need for its
Standards of Conduct rules concerning communications between
resource and transmission planners in light of the mitigation
provided by the open planning processes proposed in the NOPR.
---------------------------------------------------------------------------

    466. Commenters express a range of views on the information found
in Form 715. MidAmerican believes Form 715 to be more than adequate and
recommends shortening or eliminating it. Other investor-owned utilities
find Form 715 to be generally sufficient.\262\ Others believe the
information in Form 715, as currently supplemented by other information
in the planning process, is adequate.\263\ Duke and WAPA contend that
Form 715 does not contain sufficient information for transmission
planning, but believe that disclosure of further details should be left
to stakeholders. According to NorthWestern, Form 715 contains the basic
data, but may not always provide the needed information.
---------------------------------------------------------------------------

    \262\ E.g., Indianapolis Power, Southern, and Xcel.
    \263\ E.g., Allegheny (with data from PJM) and Nevada Companies
(with data from WECC).
---------------------------------------------------------------------------

    467. ISO/RTO Council believes that Form 715 data are generally
inadequate for planning studies, but urges the Commission not to
attempt to develop ``standardized forms'' for these and other types of
data. CAISO also cautions against adopting a standardized form for the
collection of necessary information, because standardized forms do not
necessarily provide the information needed by individual providers.
    468. A number of other commenters believe that Form 715 information
is insufficient.\264\ APPA and TAPS point out that Form 715 does not
include all the information needed to perform a load flow study,
including information on economic dispatch and interchange, and also
that Form 715 information is out of date when filed. Seattle notes that
typical sub-regional planning processes go into significantly greater
detail than Form 715 and argues that Form 715 is primarily a
reliability-focused report that seldom delves into economic analysis of
congestion and transmission options that mitigate congestion.
---------------------------------------------------------------------------

    \264\ E.g., APPA, California Commission, NCPA, CREPC, Seattle,
TAPS, and TDU Systems. California Commission and CREPC also point
out that the load forecast information presently used in planning in
the Western Interconnection is likewise insufficient.
---------------------------------------------------------------------------

    469. Several commenters contend that transparency in the planning
process is of particular interest to demand resources. New Jersey Board
suggests that each transmission provider's planning process analyze
whether demand resources or other solutions could be considered as an
alternative or a component of new transmission lines or upgrades. New
Jersey Board states that this analysis should include both supply-side
and demand-side measures such as load management, new building codes
and energy efficiency standards, the use of distributive renewable
energy systems, and renewable portfolio standards. Ohio Power Siting
Board argues that an open, transparent, and inclusive regional planning
process should include distributed generation, demand response, and new
technology as part of the mix of available options for incremental or
interim congestion relief until longer term solutions can be developed
and constructed. Fayetteville notes its general support for a SEARUC
joint planning proposal, which includes a principle that would require
the integration of demand response in planning. WIRES likewise argues
that an appropriate grid plan should be based on an integrated view of
all alternatives, including demand response and distributed generation.
PJM, Midwest ISO, and ISO New England emphasize that their planning
processes already provide for the evaluation and integration of demand
response resources.\265\ Other commenters, such as Alcoa and Steel
Manufacturer's Association, suggest that demand response resources be
considered as substitutes for certain ancillary services.
---------------------------------------------------------------------------

    \265\ See also ISO/RTO Council.
---------------------------------------------------------------------------

    470. In response to its notice convening the October 12 Technical
Conference, the Commission received several comments addressing the
role of demand response in planning. Participants in the technical
conference generally responded that demand response programs are
considered in planning, particularly in the load forecasts. Some
observed that demand response has often been difficult to incorporate
in long-term plans when it is not dispatchable and only available in
one-year increments. Participants stressed that transmission providers
must have control over a resource throughout the planning horizon if
they are to rely on that resource in lieu of constructing upgrades.
Some participants reported that this capability is available from
several forms of demand response resources.
Commission Determination
    471. The Commission adopts the NOPR's proposal and will require
transmission providers to disclose to all customers and other
stakeholders the basic criteria, assumptions, and data that underlie
their transmission system plans.\266\ In addition, transmission

providers will be required to reduce to writing and make available the
basic methodology, criteria, and processes they use to develop their
transmission plans, including how they treat retail native loads, in
order to ensure that standards are consistently applied. This
information should enable customers, other stakeholders, or an
independent third party to replicate the results of planning studies
and thereby reduce the incidence of after-the-fact disputes regarding
whether planning has been conducted in an unduly discriminatory
fashion. We note, however, that transmission providers cannot be
expected to fulfill these planning obligations unless non-public
utility transmission providers that participate in the planning process
make similar information available and, for the reasons set forth
above, we fully expect that they will do so. We believe that the same
safeguards developed as discussed above regarding the openness
principle, such as confidentiality agreements and password protected
access to information, will adequately protect against inappropriate
disclosure of confidential information or CEII.
---------------------------------------------------------------------------

    \266\ Much of the information should be available to those
engaged in transmission planning already under reliability Standards
TPL-001-0 through TPL-004-0 proposed in Docket RM06-16-000. See the
Reliability Standards NOPR. These standards set out detailed
requirements for annual studies to assess the performance of the
transmission system and require conducting simulation studies over a
five-year time horizon, with additional studies as needed for the
six to ten-year horizon. The Commission proposed that planning
entities conduct ``studies to bracket the range of probable
outcomes,'' examining system operation under variations in demand
levels, existing and planned facilities, reactive power resources,
generation dispatch and transaction patterns, controllable loads and
demand-side management, and other factors. Id. at P 1047. While we
recognize that OATT planning is distinct from these proposed
reliability planning standards, we expect that the key data
underlying transmission planning will be provided in conjunction
with reliability standards and thus should be available for
transmission planning when those standards are finalized.
---------------------------------------------------------------------------

    472. The Commission also requires that transmission providers make
available information regarding the status of upgrades identified in
their transmission plans in addition to the underlying plans and
related studies. It is important that the Commission, stakeholders,
neighboring transmission providers, and affected State authorities have
ready access to this information in order to facilitate coordination
and oversight. To the extent any such information is confidential or
consists of CEII, the transmission provider can implement the
safeguards suggested above.
    473. In response to the concerns of some commenters regarding the
disclosure of information to non-public utility transmission providers,
we believe that simultaneous disclosure of transmission planning
information where appropriate alleviates many of those concerns. In
those instances where there is non-simultaneous disclosure of
information, we find that existing reciprocity requirements ensure that
information is not inappropriately shared with the non-public utility
transmission provider's marketing affiliate.
    474. In Order No. 888-A, the Commission clarified that, under the
reciprocity condition, a non-public utility transmission provider must
also comply with the OASIS and Standards of Conduct requirements or
obtain waiver of them.\267\ We reiterate that non-public utility
transmission providers should abide by the Standards of Conduct with
regard to managing non-public transmission planning information
obtained through the planning process, consistent with their
reciprocity obligations. We also note that, given the planning process
required by this Final Rule, it may be necessary to revisit the waivers
of the Standards of Conduct granted to certain non-public utility
transmission providers in the past. We will not do so, however, on a
generic basis in this proceeding. All such existing waivers thus shall
remain in place. Whether an existing waiver of the Standards of Conduct
should be revoked will be considered on a case-by-case basis in light
of the circumstances surrounding the particular transmission
provider.\268\
---------------------------------------------------------------------------

    \267\ See Order No. 888-A at 30,286.
    \268\ We believe this same approach should also apply to public
utilities that have obtained waivers of the Standards of Conduct.
---------------------------------------------------------------------------

    475. In order for the Final Rule's transmission planning process to
be as effective as possible, we emphasize that all transmission
providers, both jurisdictional and nonjurisdictional, must be assured
that the information they provide in that process will not be used
inappropriately in the wholesale power market. While we decline to
require a third party independent facilitator as discussed below, we do
believe that utilizing an independent entity may help parties manage
Standards of Conduct concerns.\269\ Finally, we wish to emphasize that
the Commission recognizes that compliance with the Standards of Conduct
can impose costs on small entities, but we believe that this concern
must be balanced against the fact that a coordinated and open
transmission planning process is critical to remedying undue
discrimination and meeting our Nation's future energy needs and that an
open planning process cannot be fully successful if certain entities
(whether jurisdictional or nonjurisdictional) can use the information
to obtain an undue advantage in power markets. We therefore intend to
balance the costs of confidentiality restrictions with the importance
of not allowing any entity an undue competitive advantage in addressing
this issue on a case-by-case basis.
---------------------------------------------------------------------------

    \269\ The Commission will consider whether further changes to
the Standards of Conduct would facilitate the transmission planning
requirement in the Standards of Conduct NOPR initiated in Docket No.
RM07-1-000. See supra note 257. We also intend to address the
concerns of NARUC with regard to waiving the Standards of Conduct
concerning communications between resource and transmission planners
in that proceeding.
---------------------------------------------------------------------------

    476. Although we adopt the foregoing protections to ensure that
particular entities do not gain an inappropriate competitive advantage
over others, we believe that transmission providers should make as much
transmission planning information publicly available as possible,
consistent with protecting the confidentiality of customer information.
Given that one of the primary objectives of the planning reforms
adopted herein is to allow customers to consider future resource
options, it will be necessary for market participants, including the
merchant function of transmission providers, to have access to basic
transmission planning information in order to consider those options.
The simultaneous disclosure of transmission planning information can
alleviate the Standards of Conduct concerns discussed above.\270\
---------------------------------------------------------------------------

    \270\ Transmission providers could ensure simultaneous
disclosure of information through such actions as providing all
current and potential customers and other stakeholders equal access,
notice, and opportunity to attend planning meetings, providing for
the contemporaneous availability of meeting handouts and minutes on
the transmission providers' OASIS or Internet Web sites, and
requiring that an energy affiliate or marketing affiliate employee
of the transmission provider may not attend a meeting unless a
representative of at least one additional customer or potential
customer is present. We believe such actions would typically
constitute compliance with sections 358.5(a) and (b) of the
Standards of Conduct, 18 CFR 358.5(a)-(b), dealing with information
access and prohibited disclosure, respectively.
---------------------------------------------------------------------------

    477. In response to commenter concerns regarding the sufficiency of
planning information currently available in the Form 715, we find that
Form 715, as well as Form 714, have not provided customers and others
with the timely data needed to perform load flow studies and other
analyses to ensure that planning is being conducted on a comparable
basis. For example, while we understand that certain planning
information is already provided in FERC Form No. 714 (Annual Electric
Control and Planning Area Report) and FERC Form 715 (Annual
Transmission Planning and Evaluation Report), we believe that with
regard to transparency of data and assumptions, Forms 714 and 715 are
limited in a number of ways. An important limitation is that
information is not necessarily available on a consistent geographic
basis. Form 715 requires selected powerflow studies by

control area, while Form 714 requires information on control area
generation and load, including hourly load on a planning area. Since
these two areas do not necessarily coincide, it can be difficult to
apply the data except for the single annual or seasonal system peak.
Consequently, Form 715 is an insufficient basis for broad transmission
planning purposes and must be supplemented by additional assumptions
and data.
    478. Information may also be difficult to compare or apply if a
region is larger than a single control area. Where the peak periods
represented in the Form 715 correspond to different time periods in
different control areas, separate assumptions and information may be
needed for a study encompassing multiple control areas. In addition,
each control area may include different criteria for including
facilities in the data and additional assumptions will be needed to
resolve these issues as well. Moreover, information on the basis for
key assumptions is limited. The Form 715 instructions require a
description of transmission planning reliability criteria and
assessment practices, but allow the transmitting utility discretion on
what is reported. As a result, assumptions regarding key inputs, such
as the load forecasts, are not available. Similarly, information
regarding customer demand response is not available. Lastly, Form 715
requires no information explaining the basis for generator dispatch in
the powerflow cases, nor is any economic information provided. For
studies of system peak reliability, when all generators are expected to
be running, this may not be a significant limitation. However, without
some basis for dispatching the system at other times, it becomes
difficult or impossible to conduct meaningful load flow studies for
other planning purposes. Therefore, we will require the disclosure of
criteria, assumptions, data, and other information that underlie
transmission plans as described above.
    479. Finally, several commenters assert that demand response
resources should be considered in transmission planning.\271\ Some
commenters note that certain regions currently are in the process of
incorporating demand response into their transmission planning
processes.\272\ Demand resources currently provide ancillary services
in some regions, and this capability is in under development in some
others.\273\ We therefore find that, where demand resources are capable
of providing the functions assessed in a transmission planning process,
and can be relied upon on a long-term basis, they should be permitted
to participate in that process on a comparable basis.\274\ This is
consistent with EPAct 2005 section 1223.
---------------------------------------------------------------------------

    \271\ E.g., Ohio Power Siting Board, New Jersey Board, and
WIRES.
    \272\ E.g., PJM and ISO-New England.
    \273\ See Staff Report: Assessment of Demand Response & Advanced
Metering at 97-100 (Docket Number AD-06-2-000) (Demand Response
Report), available at http://www.ferc.gov/legal/staff-reports/demand-response.pdf#xml=http://search.atomz.com/search/http://search.atomz.com/search/

inklog&to=http://search.atomz.com/search/
">http://search.atomz.com/search/om/search/">http://search.atomz.com/search/
">http://search.atomz.com/search/

>http://search.atomz.com/search//

Final Rule are not intended in any way to infringe upon State
authority with regard to integrated resource planning. Rather, we
believe that the transparency provided under an open regional
transmission planning process can provide useful information which
will help states to coordinate transmission and generation siting
decisions, allow consideration of regional resource adequacy
requirements, facilitate consideration of demand response and load
management programs at the State level, and address other factors
states wish to consider.
---------------------------------------------------------------------------

d. Information Exchange
    480. In the NOPR, the Commission proposed that network transmission
customers be required to submit information on their projected loads
and resources on a comparable basis (e.g., planning horizon and format)
as used by transmission providers in planning for their native load.
The Commission further proposed that point-to-point customers be
required to submit any projections they have of a need for service over
that planning horizon and at what receipt and delivery points. The
Commission sought comment on whether specific requirements should be
adopted for this information exchange.\275\ The Commission also stated
that transmission providers must allow market participants the
opportunity to review and comment on draft transmission plans.
---------------------------------------------------------------------------

    \275\ The Commission noted in the NOPR that for network service,
some of this information is already required by sections 29, 30, and
31 of the pro forma OATT, but to the extent it is not, the
Commission proposed to require customers to provide additional
information as necessary for the transmission provider to develop a
system plan.
---------------------------------------------------------------------------

Comments
    481. Transmission providers suggest that they should be responsible
for developing a schedule and format for submission of information and
the development of a draft plan that provides sufficient time for
participants to review and comment before completion of a final
plan.\276\ EEI emphasizes the importance of requiring comparable
information from all participants in planning, including non-public
utilities. EEI maintains that similarly-situated participants should
have comparable information, with commercially-sensitive information
available only to transmission function personnel. Duke supports the
information exchange principle in general, but believes the NOPR
envisions a wider exchange of information on loads and resources than
is appropriate.\277\ Instead, Duke believes that planning participants
should agree on how much detail will be available. WAPA similarly
suggests that any criteria for information exchange should be developed
by stakeholders, not the Commission.
---------------------------------------------------------------------------

    \276\ E.g., EEI, Pinnacle, Salt River, and Xcel.
    \277\ TVA states that it is unaware of any shortcomings with the
existing information exchange process and that more specific
requirements may limit the ability of transmission providers to meet
changing needs and processes.
---------------------------------------------------------------------------

    482. Although commenters do not generally disagree with a
requirement for point-to-point customers to submit projections of their
needs for service, they question the value of these projections if the
customers have not actually requested service for these projected
needs.\278\ Nevada Companies state that point-to-point customers should
provide future use forecasts and that the forecast data transferred by
all entities should be provided for the planning horizon in a uniform
manner.
---------------------------------------------------------------------------

    \278\ E.g., APPA, Duke, and Salt River.
---------------------------------------------------------------------------

    483. Southern is concerned that the opportunity for review and
comment could be construed to apply to draft interconnection, system
impact, or facilities studies under the transmission provider's OATT.
Southern argues that such a requirement would cause great delay and
asks the Commission to clarify that the transparency requirement for
review and comment on transmission plans is limited to only the
transmission provider's draft of its base case transmission plan.
    484. Other commenters advance a view that joint planning should
consist of more than providing the transmission provider with
information and then reviewing and commenting on the plans it develops;
rather, customers need to be able to actively participate in the
development of the planning studies and transmission plans.\279\ APPA
likewise believes that earlier involvement is needed so that projected
needs are fully understood and accounted for in the initial development
of the plan.\280\ NCPA stresses that reviewing plans is meaningless if
there is no access to data on how the plan was created, how economic
evaluation was

performed, and how and why proposed upgrades were chosen. Old Dominion
suggests that planning information and data be posted no less than
monthly or, where appropriate, seasonally. TDU Systems and NCEMC stress
that LSEs should have access to all information at the same time since
if a transmission provider performs studies without including other
LSEs, it opens the door for providers to act on sensitive information
before releasing it to other LSEs.
---------------------------------------------------------------------------

    \279\ E.g., NCPA and TDU Systems.
    \280\ See also Bonneville, California Commission, Imperial,
NCPA, and Seattle.
---------------------------------------------------------------------------

    485. Some commenters advance the view that distributed generation
and other demand response resources should be considered in developing
a transmission plan.\281\
---------------------------------------------------------------------------

    \281\ E.g., New Jersey Board, Ohio Power Siting Board, and
WIRES.
---------------------------------------------------------------------------

Commission Determination
    486. The Commission adopts the information exchange principle as to
both network and point-to-point transmission customers. Accordingly, we
will require transmission providers, in consultation with their
customers and other stakeholders, to develop guidelines and a schedule
for the submittal of information. In order for the Final Rule's
planning process to be as open and transparent as possible, the
information collected by transmission providers to provide transmission
service to their native load customers must be transparent and, to that
end, equivalent information must be provided by transmission customers
to ensure effective planning and comparability. We clarify that the
information must be made available at regular intervals to be
identified in advance. Information exchanged should be a continual
process, the frequency of which should be addressed in the transmission
provider's compliance filing required by the Final Rule. However, we
expect that the frequency and planning horizon will be consistent with
ERO requirements.
    487. We also believe that it is appropriate to require point-to-
point customers to submit any projections they have of a need for
service over the planning horizon and at what receipt and delivery
points. We believe that any good faith projections of a need for
service, even though they may not yet be subject to a transmission
reservation, may be useful in transmission planning as they may, for
example, provide planners with likely scenarios for new generation
development. If the point-to-point customers do not submit such
projections, then the transmission provider cannot later be faulted for
failing to consider planning scenarios that might have taken into
account reasonable projections of future system uses that were not the
subject of specific service requests. To the extent applicable,
transmission customers also should provide information on existing and
planned demand resources and their impacts on demand and peak demand.
In addition, stakeholders should provide proposed demand response
resources if they wish to have them considered in the development of
the transmission plan.
    488. Lastly, in response to the concerns of some commenters, we
emphasize that the transmission planning required by this Final Rule is
not intended, as discussed earlier, to be limited to the mere exchange
of information and then review of transmission provider plans after the
fact. The transmission planning required by this Final Rule is intended
to provide transmission customers and other stakeholders a meaningful
opportunity to engage in planning along with their transmission
providers. At the same time, we emphasize that this information
exchange relates to planning, not other studies performed in response
to interconnection or transmission service requests.
e. Comparability
    489. In the NOPR, the Commission proposed that, after considering
the data and comments supplied by market participants, each
transmission provider develop a transmission system plan that (1) Meets
the specific service requests of its transmission customers and (2)
otherwise treats similarly-situated customers (e.g., network and retail
native load) comparably in transmission system planning.
Comments
    490. Several commenters support the comparability principle,\282\
and others state that existing processes already follow this
principle.\283\ EEI urges the Commission to emphasize that the
``comparability'' principle requires the transmission provider or
transmission owner to treat similarly-situated participants comparably
in the development of a plan, but does not require that all
participants be treated equally. Pinnacle and others support comparable
treatment of similarly-situated customers and request the Commission to
confirm that native load protections will be recognized in the concept
of comparability.\284\ New Mexico Attorney General asserts that native
load and non-affiliated merchants and other wholesale customers should
not be treated comparably, because utilities have a statutory
obligation to serve.
---------------------------------------------------------------------------

    \282\ E.g., California Commission, NCPA, CREPC, Salt River,
Seattle, and WAPA.
    \283\ E.g., Duke and Imperial.
    \284\ See also MidAmerican, Progress Energy, and Xcel.
---------------------------------------------------------------------------

    491. TDU Systems and the NRECA repeat the view that comparability
cannot be achieved if the transmission provider is the only one
developing the plan, which they believe this principle contemplates.
They argue instead that LSEs should be allowed to participate actively
in the development of the plan from the beginning and should have equal
weight in decision-making. TDU Systems believes that comparability does
not allow for different planning standards for certain customers,
because it may leave rural electric cooperatives out of the planning
loop.\285\ TAPS also argues that comparability is not enough; rather,
substantive goals should be included.\286\
---------------------------------------------------------------------------

    \285\ See also NRECA Reply and Old Dominion.
    \286\ TAPS cites to its ``Balanced Principles for Transmission
Planning & Expansion,'' which was attached to its NOI comments, for
a description of the following substantive goals: (1) Reliability/
adequacy, (2) accommodating load growth, (3) preserving existing
transmission rights, (4) access to regional competitive generation
markets, (5) maintaining deliverability, (6) facilitating regional/
inter-regional power transfers, and (7) integrating new generation
into the regional grid. TAPS emphasizes that the process should
anticipate needs and propose solutions before serious transmission
problems emerge.
---------------------------------------------------------------------------

    492. Noting that not all transmission service requests may be
granted, Southern urges the Commission to clarify that the intent of
this criteria is that the transmission provider plan its system so as
to be able to reliably serve all of its long-term firm commitments on
its transmission system in accordance with its State and Federal legal
requirements, as well as ERO Standards. With regard to RTO and ISO
planning, NYAPP argues that it is not comparable for an RTO or ISO to
only plan for bulk power facilities, while allowing individual
transmission owners the discretion to plan for lower voltage
transmission facilities.
    493. Some commenters argue that demand resources should be treated
comparably to other resources in transmission planning.\287\
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    \287\ E.g., ELCON, New Jersey Board, and WIRES.
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Commission Determination
    494. The Commission adopts the NOPR's proposal as to the
comparability principle and will require the transmission provider,
after considering the data and comments supplied by customers and other
stakeholders, to develop a transmission system plan that (1) Meets the
specific service requests of

its transmission customers and (2) otherwise treats similarly-situated
customers (e.g., network and retail native load) comparably in
transmission system planning.\288\ Further, we agree with commenters
that customer demand resources should be considered on a comparable
basis to the service provided by comparable generation resources where
appropriate.
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    \288\ As discussed above, we emphasize that the obligation
imposed herein on transmission providers is meant to include
transmission owners in RTOs and ISOs that no longer have their own
OATTs, as well as non-public utility transmission providers required
to comply with the Final Rule's planning process consistent with
their reciprocity obligations.
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    495. We are specifically requiring a comparability principle to
address concerns, such as those raised by commenters, that transmission
providers continue to plan their transmission systems such that their
own interests are addressed without regard to, or ahead of, the
interests of their customers. Comparability requires that the interests
of transmission providers and their similarly-situated customers be
treated on a comparable basis. In response to the concerns expressed by
several commenters, we emphasize that similarly-situated customers must
be treated on a comparable basis, not that each and every transmission
customer should be treated the same.\289\
f. Dispute Resolution
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    \289\ Additionally, in our discussion of the coordination
principle above, we clarify that transmission planning is the tariff
obligation of each transmission provider, and as such, ultimate
responsibility for planning remains with transmission providers.
Accordingly, we reject the arguments made by some commenters that
comparability requires that customers have equal weight in decision-
making.
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    496. In the NOPR, the Commission proposed that transmission
providers propose a dispute resolution process, such as requiring
senior executives to meet prior to the filing of any complaint and
using a third party neutral. The Commission noted that the Commission's
Dispute Resolution Service is available to assist transmission
providers in developing a dispute resolution process. The Commission
also noted that, in addition to informal dispute resolution, affected
parties would have the right to file complaints with the Commission
under FPA section 206. The Commission sought comment on whether any
specific dispute resolution processes should be required.
Comments
    497. Many commenters support the proposed dispute resolution
principle,\290\ while others believe existing processes, including
section 12 of the pro forma OATT, are sufficient.\291\ Other commenters
simply urge flexibility in the development of a dispute resolution
process.\292\ However, maintaining that the Commission has no legal
authority to mandate a regional planning process or dispute resolution
related thereto, Progress states the Commission should be flexible and
allow for a voluntary dispute resolution process.\293\
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    \290\ E.g., APPA, Bonneville, California Commission, Imperial,
and NCPA.
    \291\ E.g., East Texas Cooperatives, Salt River, Seattle, TVA
and WAPA. TVA points out that since planning and its principles are
just now being formed, resources would be better spent on developing
platforms where interested parties could have input into the
planning process, as opposed to dispute resolution.
    \292\ E.g., Allegheny, Nevada Companies, Pinnacle, and Southern.
Xcel, however, does not believe any dispute resolution process is
required in the OATT.
    \293\ See also Duke and MidAmerican.
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    498. Southern believes that dispute resolution should be limited to
whether a provider has complied with any procedural requirements and
not be utilized by parties to modify a transmission plan. APPA,
however, argues that such an approach would relegate customers to an
advisory role. EEI believes the Commission should include principles
for dispute resolution and should allow stakeholders in the regional
planning groups to craft their own procedures consistent with those
principles. Reflecting concerns of some of its members, EEI cautions
against mandating dispute resolution that includes binding resolution
of whether, how, where, or when to construct additional transmission
facilities.
    499. Indianapolis Power believes there should be a dispute
resolution process in place with specific steps identified, expressing
reservations about the vagueness of the current MISO process. ATC
argues that RTO plans should recognize which entity is ultimately
accountable for building transmission, by requiring transmission
customers that have a dispute with a plan first to appeal to the local
transmission owner to ensure both entities fully understand what is
being requested, before carrying the dispute further.
    500. Consistent with its focus on integrated joint planning, TDU
Systems asks that the Commission clarify that a dispute resolution
process is not being required as a principle as an acknowledgement that
transmission providers will retain control over the process. As long as
LSEs are an integral part of the planning process, TDU Systems stress
that there should be no need for an elaborate dispute resolution
process.
Commission Determination
    501. The Commission adopts the NOPR's proposal to require
transmission providers to develop a dispute resolution process to
manage disputes that arise from the Final Rule's planning process.\294\
An existing dispute resolution process may be utilized, but those
seeking to rely on an existing dispute resolution process must
specifically address how its procedures will be used to address
planning disputes. The dispute resolution process should be available
to address both procedural and substantive planning issues, as the
purpose for including a dispute resolution process is to provide a
means for parties to resolve all disputes related to the Final Rule's
planning process before turning to the Commission.
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    \294\ We have already addressed arguments concerning our
jurisdiction to require a transmission planning process. A process
for resolving disputes that arise from that planning process is a
necessary incident to it.
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    502. We emphasize that the intent of the dispute resolution process
required here is not to address issues over which the Commission does
not have jurisdiction, such as a transmission provider's planning to
serve its retail native load or State siting issues. As discussed
above, however, we do intend that the planning process required by this
Final Rule ensure comparability in planning between that conducted for
a transmission provider's retail native load and its similarly-situated
transmission customers and, therefore, issues relating to such
comparability may be appropriate for the dispute resolution process.
    503. Lastly, we encourage transmission providers, customers, and
other stakeholders to utilize the Commission's Dispute Resolution
Service to help develop a three step dispute resolution process,
consisting of negotiation, mediation, and arbitration. Regardless of
the process adopted by a transmission provider, affected parties of
course would retain any rights they may have under FPA section 206 to
file complaints with the Commission.
g. Regional Participation
    504. In addition to preparing a system plan for its own control
area on an open and nondiscriminatory basis, the Commission proposed in
the NOPR that each transmission provider be required to coordinate with
interconnected systems to: (1) Share system plans to ensure that they
are simultaneously feasible and otherwise use consistent

assumptions and data, and (2) identify system enhancements that could
relieve ``significant and recurring'' transmission congestion (defined
below). The Commission emphasized that such coordination should
encompass as broad a region as possible, given the interconnected
nature of the transmission grid and the efficiency of addressing these
issues in a single forum. The Commission also recognized that, as in
the West, it may be appropriate to organize regional planning efforts
on both a sub-regional and regional level. The Commission sought
comment on whether there are existing institutions (such as the NERC
regional councils or sub-regional planning groups) that are well-
situated to perform or coordinate this function.
Comments
Regional Scope
    505. EEI agrees that regional planning should be encouraged, but
urges the Commission not to be prescriptive about the size of the
regions involved. According to EEI, the Commission should define
regional planning as planning that involves more than one transmission
provider and allow the regions to define themselves. CAISO believes the
Commission should leave the determination of the sub-regional and
regional boundaries to transmission providers. NC Transmission Planning
Participants assert on reply that the participants in each regional
process are in the best position determine the proper scope of the
planning process for their region. NRECA argues that customers and
other stakeholders should be allowed to participate in the discussion