agreement of Interconnection Customer and Transmission Owner or
Transmission Provider, they shall be solely funded by
Interconnection Customer.

    119. The Commission also sought comment on whether to limit the
proposal to RTOs/ISOs or to apply it to all transmission providers.
b. Comments
    120. A number of commenters support the proposal.\197\ A group of
five commenters, predominantly from MISO, oppose the proposal and state
that any action would be premature, given that, at the time that they
filed their comments, the D.C. Circuit had not issued a decision in the
Otter Tail proceedings. They ask the Commission to refrain from
implementing this reform until the appellate decision is issued.\198\
---------------------------------------------------------------------------

    \197\ Non-Profit Utility Trade Associations; AFPA; AWEA; CAISO;
Joint Renewable parties; Generation Developers; EDP; ELCON; FTC;
IECA; NEPOOL; NextEra; PG&E SEIA; TDU Systems.
    \198\ Duke 2017 Comments at 6-7; EEI 2017 Comments at n.20; ITC
2017 Comments at 8; MidAmerican 2017 Comments at 11; MISO TOs 2017
Comments at 17.
---------------------------------------------------------------------------

    121. Regarding whether the Commission should extend the requirement
for mutual agreement beyond RTOs/ISOs, AWEA, Joint Renewable Parties,
TDU Systems, and AFPA all argue that the proposal should apply
generically.\199\ On the other hand, Southern, TVA, Generation
Developers, and Xcel state that self-funding by the transmission owner
is not applicable to the pro forma OATT.\200\
---------------------------------------------------------------------------

    \199\ AWEA 2017 Comments at 19; Joint Renewable Parties 2017
Comments at 9-10; TDU Systems 2017 Comments at 7; AFPA Comments at
7.
    \200\ Southern 2017 Comments at 13-14; TVA 2017 Comments at 5;
Generation Developers 2017 Comments at 15; Xcel 2017 Comments at 10-
11.
---------------------------------------------------------------------------

c. Commission Determination
    122. We withdraw the NOPR's proposal to extend the approach to
self-funding that the Commission approved in MISO to all regions. On
January 26, 2018, the D.C. Circuit issued a decision vacating the
Commission's orders in the Otter Tail proceedings.\201\ In this
decision, the court noted, among other things, that the Commission did
not adequately respond to the argument that ``involuntary generator
funding compels [transmission owners] to . . . accept additional risk
without corresponding return.'' \202\ The court further stated that the
Commission's approved changes to the MISO tariff ``open[ ] the
floodgates to involuntary generator-funded interconnection projects.''
\203\ The court also referenced this proceeding, stating that the fact
that the Commission ``plans a rulemaking to consider interconnection
problems and costs . . . suggests that it should approach those issues
on a clean slate.'' \204\ In light of the D.C. Circuit's decision, we
will not move forward with the proposal pertaining to self-funding at
this time. We will, however, continue to evaluate the issue.
---------------------------------------------------------------------------

    \201\ Ameren Servs. Co. v. FERC, 880 F.3d 571 (D.C. Cir. 2018).
    \202\ Id. at 573-74.
    \203\ Id. at 584.
    \204\ Id. at 585.
---------------------------------------------------------------------------

4. Dispute Resolution
a. NOPR Proposal
    123. In the NOPR, the Commission proposed that RTOs/ISOs establish
interconnection dispute resolution procedures that allow a disputing
party to unilaterally seek dispute resolution in RTO/ISO regions.\205\
---------------------------------------------------------------------------

    \205\ NOPR, FERC Stats. & Regs. ] 32,719 at P 78.
---------------------------------------------------------------------------

    124. Order No. 2003 created an arbitration process through the
adoption of section 13.5 of the pro forma LGIP, which allows disputing
parties to agree to arbitration ``upon mutual agreement of the
Parties'' to the dispute.\206\ Pursuant to this process, arbitrators
may interpret and apply the provisions of the LGIA and LGIP but have no
power to modify those provisions.\207\ At the completion of this
process, the arbitrator's decision is ``final and binding upon the
Parties, and judgment on the award may be entered in any court having
jurisdiction.'' Additionally, the decision may only ``be appealed . . .
on the grounds that the conduct of the arbitrator(s), or the decision
itself, violated the standards set forth in the Federal Arbitration Act
or the Administrative Dispute Resolution Act.'' \208\ While the
arbitrator's decision is binding, ``the final decision must still be
filed with [the Commission] if it affects jurisdictional rates, terms
and conditions of service, Interconnection Facilities, or Network
Upgrades,'' \209\ and the Commission ``retains the authority to review
the arbitrator's decision.'' \210\ Participation in the section 13.5
arbitration process does not limit the ability of either party to bring
a complaint about the same issues.\211\
---------------------------------------------------------------------------

    \206\ Pro forma LGIP Section 13.5.1.
    \207\ Pro forma LGIP Section 13.5.
    \208\ Pro forma LGIP Section 13.5.3.
    \209\ Id.
    \210\ Order No. 2003, FERC Stats. & Regs. ] 31,146 at P 290.
    \211\ Specifically, it states that section 13.5 arbitration does
not ``circumscribe[ ] the Parties' right to avail themselves of the
Commission's complaint process because under section 13.5.1, a party
that does not agree to arbitration may exercise its rights,
including its right to bring a complaint to the Commission.'' Order
No. 2003, FERC Stats. & Regs. ] 31,146 at P 290.
---------------------------------------------------------------------------

    125. In the NOPR, the Commission proposed to revise the Code of
Federal Regulations to require RTOs/ISOs to establish interconnection
dispute resolution procedures that would allow a disputing party to
unilaterally seek dispute resolution. In particular, the Commission
proposed to revise Sec.  35.28 of the Commission's regulations to add

a new paragraph (g)(9), providing that every Commission-approved
independent system operator or regional transmission organization
tariff must contain provisions governing generator interconnection
dispute resolution procedures to allow a disputing party to
unilaterally initiate dispute resolution procedures under the
respective tariff. Such provisions must provide for independent system
operator or regional transmission organization staff member(s) or
utilize subcontractor(s) to serve as the neutral decision-maker(s) or
presiding staff member(s) or subcontractor(s) to the dispute resolution
procedures. Such staff participating in dispute resolution procedures
shall not have any current or past substantial business or financial
relationships with any party. Additionally, such dispute resolution
procedures must account for the time sensitivity of the generator
interconnection process.
    126. The Commission limited the proposed requirements in this draft
text to RTOs/ISOs because the Commission had only received comments
regarding the need for dispute resolution reform in RTOs/ISOs. However,
given the lack of a record on this issue, the Commission also sought
comment on the need for reform outside the RTOs/ISOs.\212\ The
Commission also sought comment on the appropriateness of adopting
procedures similar to section 4.2 of the pro forma SGIP, which allows
parties to contact the Commission's Dispute Resolution Service (DRS)
for assistance in resolving an interconnection dispute.\213\
---------------------------------------------------------------------------

    \212\ NOPR, FERC Stats. & Regs. ] 32,719 at P 86.
    \213\ Section 4.2.4 of the pro forma SGIP states that DRS will
assist in resolving a dispute or in selecting an appropriate dispute
resolution venue. Additionally, section 4.2.6 states that if neither
party elects to contact DRS or if the attempted dispute resolution
fails, ``either Party may exercise whatever rights and remedies it
may have in equity or law consistent with the terms of these
procedures.''
---------------------------------------------------------------------------

    127. The NOPR proposal represented a potential alternative to, and
not a replacement of, section 13.5 of the pro forma LGIP.\214\ The
Commission crafted its proposal in response to its observation that the
arbitration process embodied in section 13.5 is effectively unavailable
to an interconnection customer if a transmission owner opposes this
arbitration process.\215\
---------------------------------------------------------------------------

    \214\ Id.
    \215\ Id. P 85.
---------------------------------------------------------------------------

b. General
i. Comments
    128. Multiple commenters support the proposal.\216\ The Non-Profit
Utility Trade Associations state that they do not object to this
proposal.\217\ Salt River states that the proposal is reasonable with
regard to disputes between interconnection customers and RTOs/ISOs,
RTO/ISO transmission owners, or affected system operators that are also
RTO/ISO transmission owners.\218\ However, Salt River argues that if
the dispute is with an autonomous neighboring affected system operator
that is a non-RTO/ISO member, then the dispute resolution procedures in
the affected system operator's OATT should apply.\219\
---------------------------------------------------------------------------

    \216\ AWEA 2017 Comments at 21; Joint Renewable Parties 2017
Comments at 2-3; IECA 2017 Comments at 3; Invenergy 2017 Comments at
15-16; AFPA 2017 Comments at 8; CAISO 2017 Comments at 11-12; SEIA
2017 Comments at 14-15; TDU Systems 2017 Comments at 11; AVANGRID
2017 Comments at 18.
    \217\ Non-Profit Utility Trade Associations 2017 Comments at 6.
    \218\ Salt River 2017 Comments at 8.
    \219\ Id.
---------------------------------------------------------------------------

    129. AES asserts that RTOs/ISOs, not the Commission, should
reexamine their existing dispute resolution procedures.\220\ Indicated
NYTOs oppose the dispute resolution proposal, arguing that NYISO's
existing dispute resolution provisions are adequate.\221\ NYISO also
opposes the proposed revisions, stating that they would duplicate
existing dispute resolution opportunities.\222\ ISO-NE and CAISO
similarly argue that their current dispute resolution procedures are
adequate.\223\ CAISO also notes that its tariff includes a dedicated
dispute committee for generator interconnection issues.\224\
MidAmerican argues that the existing MISO tariff addresses the
Commission's concerns about the ability of a party to unilaterally
request dispute resolution.\225\
---------------------------------------------------------------------------

    \220\ AES 2017 Comments at 7-8.
    \221\ Indicated NYTOs 2017 Comments at 12-14.
    \222\ NYISO 2017 Comments at 17.
    \223\ ISO-NE 2017 Comments at 18; CAISO 2017 Comments at 12.
    \224\ Id. (citing CAISO, eTariff, FERC Electric Tariff, OATT,
Section 13 (0.0.0) & app. DD, Section 15.5 (1.0.0)).
    \225\ MidAmerican 2017 Comments at 7; see also MISO TOs 2017
Comments at 24.
---------------------------------------------------------------------------

    130. MISO requests a clarification that RTOs/ISOs do not need to
create separate dispute resolution procedures for generator
interconnection disputes and may continue to rely on their general
dispute resolution procedures as long as they permit parties to
unilaterally initiate the resolution process.\226\ MISO TOs ask the
Commission to clarify that the dispute resolution procedures are for
genuine disputes only and should not be used to gain additional time to
meet LGIP or LGIA obligations.\227\ PJM agrees with the dispute
resolution proposal and believes that its dispute resolution procedures
generally conform to it.\228\
---------------------------------------------------------------------------

    \226\ MISO 2017 Comments at 17-18.
    \227\ MISO TOs 2017 Comments at 24.
    \228\ PJM 2017 Comments at 8.
---------------------------------------------------------------------------

    131. Generation Developers request that the final action state that
the dispute resolution mechanism that an RTO/ISO adopts should trump
the existing provisions in section 13.5 of the LGIP. Generation
Developers state that, unless this is made clear, the parties will
argue about which dispute resolution provision applies.\229\
---------------------------------------------------------------------------

    \229\ General Developers 2017 Comments at 19.
---------------------------------------------------------------------------

ii. Commission Determination
    132. In this final action, we revise the pro forma LGIP to add new
section 13.5.5, as discussed further below. We are taking this step
because the record in this proceeding indicates that existing dispute
resolution procedures may not be just and reasonable and may be unduly
discriminatory or preferential because one disputing party may
effectively prevent the other disputing party from pursuing dispute
resolution.\230\ We thus disagree with those commenters that argue that
transmission providers should simply reexamine their dispute resolution
procedures. The reason is that, if the status quo provides little
recourse for interconnection customers when a transmission provider
does not agree to dispute resolution, then it would not be sufficient
for transmission providers to merely reexamine their dispute resolution
procedures with no guarantee that they would address this concern.
Additionally, as discussed further below, we find that the record
developed here demonstrates the need for generic dispute resolution
reform, both inside and outside RTOs/ISOs. To avoid having dispute
resolution requirements in multiple places, we are effectuating this
reform through revisions to the pro forma LGIP as part of the existing
dispute resolution provisions, rather than through changes to the Code
of Federal Regulations.
---------------------------------------------------------------------------

    \230\ NOPR, FERC Stats. & Regs. ] 32,719 at P 84.
---------------------------------------------------------------------------

    133. Therefore, this final action revises the pro forma LGIP by
adding new section 13.5.5, which will read as follows:

    Non-binding dispute resolution procedures. If a Party has
submitted a Notice of Dispute pursuant to section 13.5.1, and the

Parties are unable to resolve the claim or dispute through
unassisted or assisted negotiations within the thirty (30) Calendar
Days provided in that section, and the Parties cannot reach mutual
agreement to pursue the section 13.5 arbitration process, a Party
may request that Transmission Provider engage in Non-binding Dispute
Resolution pursuant to this section by providing written notice to
Transmission Provider (``Request for Non-binding Dispute
Resolution''). Conversely, either Party may file a Request for Non-
binding Dispute Resolution pursuant to this section without first
seeking mutual agreement to pursue the section 13.5 arbitration
process. The process in section 13.5.5 shall serve as an alternative
to, and not a replacement of, the section 13.5 arbitration process.
Pursuant to this process, a transmission provider must within 30
days of receipt of the Request for Non-binding Dispute Resolution
appoint a neutral decision-maker that is an independent
subcontractor that shall not have any current or past substantial
business or financial relationships with either Party. Unless
otherwise agreed by the Parties, the decision-maker shall render a
decision within sixty (60) Calendar Days of appointment and shall
notify the Parties in writing of such decision and reasons
therefore. This decision-maker shall be authorized only to interpret
and apply the provisions of the LGIP and LGIA and shall have no
power to modify or change any provision of the LGIP and LGIA in any
manner. The result reached in this process is not binding, but,
unless otherwise agreed, the Parties may cite the record and
decision in the non-binding dispute resolution process in future
dispute resolution processes, including in a section 13.5
arbitration, or in a Federal Power Act section 206 complaint. Each
Party shall be responsible for its own costs incurred during the
process and the cost of the decision-maker shall be divided equally
among each Party to the dispute.

    134. The provision retains the central principles of the NOPR
proposal but extends its application to all transmission providers,
including non-RTOs/ISOs. We have revised the provision to also provide
necessary clarification in response to the comments received in this
proceeding, as discussed further below.
    135. We note that numerous parties have expressed a need for
dispute resolution reform and support for the principles embodied in
the NOPR proposal. While this final action establishes the core
requirement that transmission providers adopt a new non-binding dispute
resolution process, each transmission provider must develop and
establish the additional specifics of a just and reasonable process
that allows disputing parties to unilaterally seek non-binding dispute
resolution.
    136. In response to Salt River's argument regarding the
applicability of the proposed revisions to an autonomous neighboring
affected system operator, as explained more fully below, on April 3-4,
2018, the Commission convened a technical conference in Docket No.
AD18-8-000 for industry representatives and others to discuss issues
related to affected systems. Given that the discussion here pertains to
disputes within a transmission provider's region (such as a dispute
between an interconnection customer and a transmission provider) and
not to disputes with a party external to the region of the
interconnection request, we find that Salt River's concerns are better
addressed in a proceeding dedicated to issues involving affected
systems, such as the aforementioned technical conference.\231\
---------------------------------------------------------------------------

    \231\ Initial and reply comments on the technical conference in
Docket No. AD18-8-000 are due within 30 days and 45 days,
respectively, from the date of the issuance of the Notice Inviting
Post-Technical Conference Comments in that proceeding, which issued
concurrently with this final action.
---------------------------------------------------------------------------

    137. In response to Indicated NYTOs', ISO-NE's, NYISO's, PJM's,
MISO's, MidAmerican's, and CAISO's contentions about the existing
dispute resolution procedures in their specific regions, we remind
these parties that we will not evaluate a particular transmission
provider's tariff provisions until it submits its compliance filing. We
note, however, that a transmission provider that has only adopted the
generator interconnection dispute resolution procedures imposed by
Order No. 2003, namely the section 13.5 arbitration process, would not
comply with the non-binding dispute resolution requirements of this
final action, as set forth in the new section 13.5.5 above.
    138. In response to MISO's request for clarifications, we find that
a transmission provider does not need to create dispute resolution
procedures that only apply to generator interconnection disputes, so
long as the transmission provider provides a dispute resolution process
that a party, including the interconnection customer, may seek
unilaterally. In response to the MISO TOs' request for clarification,
we find that their concern that a party will use the dispute resolution
process to gain additional time to meet LGIP or LGIA obligations to be
speculative, and, to the extent that this is a valid concern, it would
apply equally to disputing interconnection customers and transmission
providers or owners. In addition, both the dispute resolution process
created here and the section 13.5 arbitration process impose costs on
the disputing parties, which should mitigate concerns about potential
misuse of the process.
    139. We find that the new dispute resolution provisions in section
13.5.5 of the pro forma LGIP adopted by this final action do not trump
the existing language in section 13.5 of the pro forma LGIP. We
establish the new non-binding dispute resolution process here primarily
to address the concern that dispute resolution is unavailable where
there is no mutual agreement to pursue a section 13.5 arbitration. This
final action thus provides a dispute resolution avenue that one party
may seek unilaterally. Disputing parties are free to determine which
process they prefer, and disputing parties may pursue the non-binding
process even if they have not previously sought a section 13.5
arbitration. Additionally, participation in the new section 13.5.5
process does not preclude the parties from pursuing arbitration after
the conclusion of another process if they seek a binding result. Also,
pursuing either process does not prevent either party from availing
itself of the complaint process pursuant to section 206 of the FPA.
Furthermore, we note that we do not restrict a party's ability to cite
the record developed in the arbitration process described in section
13.5 of the pro forma LGIP in a complaint proceeding pursuant to
section 206 of the FPA, and we see no reason to impose such a
restriction for the non-binding dispute resolution provisions adopted
in this final action. We note, however, that parties may mutually agree
to restrict the use of the record created in a non-binding dispute
resolution process.
c. Extending the Dispute Resolution Proposal beyond RTOs/ISOs
i. Comments
    140. Generation Developers, IECA, Competitive Suppliers, and TDU
Systems argue that the Commission should also reform dispute resolution
procedures outside of RTOs/ISOs.\232\ For example, Generation
Developers state that problems that interconnection customers encounter
pertaining to dispute resolution ``are also encountered with a
Transmission Provider outside of [an RTO/ISO].'' \233\ TDU Systems
state that they have ``found the current dispute resolution processes
[outside of RTOs/ISOs] to be inadequate,'' because, for example, in
regions that lack an RTO/ISO-like entity ``to assist in resolving
disputes, the waiting period to access dispute

resolutions is too long, and parties to disputes should have options
beyond mutually-agreed upon arbitration.'' \234\ In non-RTO/ISO
regions, AFPA recommends the establishment of a separate Commission
dispute resolution service with expertise on these matters.\235\
Competitive Suppliers believe that the rules and protocols in organized
markets are superior to those outside organized markets and encourage
the Commission to uphold consistency and comparability unless there is
an adequate reason to allow regional variation.\236\ MISO asserts that
there is no basis to conclude that the procedures currently used in
RTOs/ISOs are inferior to the procedures used by other transmission
providers.\237\
---------------------------------------------------------------------------

    \232\ Generation Developers 2017 Comments at 18-20; IECA 2017
Comments at 3; Competitive Suppliers 2017 Comments at 6; TDU Systems
2017 Comments at 11.
    \233\ Generation Developers 2017 Comment at 20.
    \234\ TDU Systems 2017 Comments at 12.
    \235\ AFPA 2017 Comments at 8.
    \236\ Competitive Suppliers 2017 Comments at 5.
    \237\ MISO 2017 Comments at 17.
---------------------------------------------------------------------------

    141. TVA believes that the current dispute resolution process for
non-RTOs/ISOs is sufficient, under both the pro forma LGIP and the pro
forma SGIP.\238\ If the Commission decides that any final action should
align more closely to the parameters of the NOPR, Competitive Suppliers
argue that the proposed revisions to the dispute resolution changes
should apply to all transmission owners and providers offering
interconnection service.\239\
---------------------------------------------------------------------------

    \238\ TVA 2017 Comments at 6.
    \239\ Competitive Suppliers 2017 Comments at 6.
---------------------------------------------------------------------------

ii. Commission Determination
    142. In this final action, we adopt the aforementioned pro forma
LGIP language, which imposes the revised dispute resolution
requirements on both RTOs/ISOs and non-RTOs/ISOs. As noted above, the
Commission sought comment on the need for dispute resolution reform
outside of RTOs/ISOs. We agree with commenters that there is a need for
dispute resolution reform outside of RTO/ISOs.\240\ Outside of the
RTOs/ISOs, the transmission provider and transmission owner are the
same entity. Consequently, outside of RTOs/ISOs and without the
presence of an independent RTO/ISO as a third party, it may be more
difficult for the transmission provider and the interconnection
customer to reach mutual agreement to seek dispute resolution. Under
such circumstances, when a dispute arises, the process would benefit
from a neutral decision-maker that can evaluate the dispute without an
interest in the outcome. For this reason, the procedures adopted here
apply generically, in both RTO/ISO regions and non-RTO/ISO regions.
Finally, we have opted to include new pro forma LGIP section 13.5.5 in
the pro forma LGIP instead of the Code of Federal Regulations, so that
all generically applicable generator interconnection dispute resolution
requirements are in the same place.
---------------------------------------------------------------------------

    \240\ Competitive Suppliers 2017 Comments at 5; MISO 2017
Comments at 17.
---------------------------------------------------------------------------

d. RTO/ISO Neutrality
i. Comments
    143. Multiple commenters question the neutrality of RTO/ISO staff
or oppose allowing RTO/ISO staff as dispute resolution neutral
decision-makers.\241\ AWEA, for instance, notes that RTOs/ISOs rely
upon transmission owner assistance (for modeling and design
information) and transmission owner membership (for financial support)
and that, on occasion, RTOs/ISOs have refused to participate in dispute
resolution.\242\ Another option that AWEA and NextEra suggest is for
RTOs/ISOs to contract for staff from a disinterested RTO/ISO to oversee
their dispute resolution.\243\ NextEra suggests adding a draft tariff
provision that would allow for this arrangement.\244\
---------------------------------------------------------------------------

    \241\ FTC 2017 Comments at 11; AWEA 2017 Comments at 23-24;
Generation Developers 2017 Comments at 18; EDP 2017 Comments at 5;
NextEra 2017 Comments at 15; AVANGRID 2017 Comments at 18.
    \242\ AWEA 2017 Comments at 22-23.
    \243\ Id. at 23; NextEra 2017 Comments at 20.
    \244\ Id. at 17.
---------------------------------------------------------------------------

    144. AWEA also states that market monitors have the necessary
independence to oversee dispute resolution, but they already have
significant responsibilities and may lack relevant interconnection
process experience.\245\ EEI argues that having an RTO/ISO serve as a
decision-maker in a dispute could potentially challenge its
independence and neutrality.\246\ Similarly, Indicated NYTOs argue that
entities like NYISO would be reluctant to resolve such disputes by
making judgments in favor of either the developer or the transmission
owner.\247\ ISO-NE and NEPOOL explain that ISO-NE fulfills the role of
transmission provider for many functions but that participating
transmission owners serve in this role when providing cost estimates
for network upgrades.\248\ ISO-NE and NEPOOL also state that, given
ISO-NE's transmission provider role, disputes can arise between ISO-NE
and the interconnection customer or the transmission owner, and it
would therefore be inappropriate to require ISO-NE to decide these
disputes.\249\ NEPOOL also argues that having RTO/ISO staff resolve
disputes could impair the RTO's/ISO's performance of its core
duties.\250\ NextEra suggests that RTO/ISO staff serving in this role
would need comparable status to the RTO's/ISO's independent market
monitoring staff.\251\ TDU Systems state that RTO/ISO staff are likely
adequately independent from all market participants and able to serve
as a useful resource for resolving disputes.\252\ AVANGRID states that,
while RTO/ISO staff are often ``very good'' at preventing and resolving
disputes as they arise, they should not ``be put in the position of
determining the outcome of formal dispute resolution processes.'' \253\
---------------------------------------------------------------------------

    \245\ AWEA 2017 Comments at 24.
    \246\ EEI 2017 Comments at 28.
    \247\ Indicated NYTOs 2017 Comments at 14.
    \248\ ISO-NE 2017 Comments at 18-19; NEPOOL 2017 Comments at 8.
    \249\ ISO-NE 2017 Comments at 19.
    \250\ NEPOOL 2017 Comments at 8.
    \251\ NextEra 2017 Comments at 15.
    \252\ TDU Systems 2017 Comments at 11.
    \253\ AVANGRID 2017 Comments at 18.
---------------------------------------------------------------------------

    145. Generation Developers and NextEra argue that subcontractors
could serve as neutral parties.\254\ AWEA also argues that the NOPR's
neutrality standard may be too vague and that subcontractor vetting may
resolve this concern.\255\ Generation Developers state that the RTO/ISO
should maintain a long-term contract for dispute services to ensure
that the subcontractor is neutral and not beholden to the RTO/ISO.
Generation Developers propose that the RTO/ISO should have a list of
subcontractors with substantial experience in interconnection and
modeling matters that are available to serve as neutral third-parties,
and that all RTO/ISO members should be allowed to propose to use the
listed subcontractors. Generation Developers propose that subcontractor
fees should be borne by interconnection customers to ensure that there
is no tendency for a subcontractor to be beholden to the RTO/ISO.
---------------------------------------------------------------------------

    \254\ Generation Developers 2017 Comments at 18; NextEra 2017
Comments at 15-16; see also AVANGRID 2017 Comments at 18.
    \255\ AWEA 2017 Comments at 23.
---------------------------------------------------------------------------

    146. Conversely, MISO contends that there is no need for
independent staff or subcontractors and that the proposed requirements
could increase RTO/ISO bureaucratization and impose additional
costs.\256\ MISO states that the proposed independence requirements are
unnecessary, as RTOs/ISOs are already subject to stringent independence
requirements. MISO asserts that there has been no showing that the
existing conflict of interest requirements are inadequate for purposes
of dispute resolution. MISO proposes that the Commission permit RTOs/
ISOs to rely

on their existing standards of conduct and similar requirements for
their dispute resolution staff.\257\
---------------------------------------------------------------------------

    \256\ MISO 2017 Comments at 19.
    \257\ Id. at 18-19.
---------------------------------------------------------------------------

    147. MISO states that the requirement that RTO/ISO dispute
resolution staff not have current or past substantial business or
financial relationships with any disputing party is too broad and
burdensome and that the pool of suitable candidates to perform these
tasks is limited. If the Commission adopts this requirement, MISO asks
the Commission to limit the prohibition to a reasonable time period
(e.g., three years).\258\
---------------------------------------------------------------------------

    \258\ Id. at 19.
---------------------------------------------------------------------------

    148. NYISO is concerned about instituting a framework that would
outsource responsibility to subcontractors.\259\ It states that section
30.13.2 of its LGIP provides that, even when NYISO uses subcontractors,
it must comply with the tariff's requirements. Therefore, NYISO objects
to any process that would allow a subcontractor's determination--for
example, regarding appropriate network upgrades--to override NYISO's
judgment concerning tariff requirements and applicable reliability
standards.\260\
---------------------------------------------------------------------------

    \259\ NYISO 2017 Comments at 18.
    \260\ Id.
---------------------------------------------------------------------------

ii. Commission Determination
    149. With few exceptions, the commenters voice strong opposition to
having RTO/ISO staff serve as decision-makers in dispute resolution
proceedings. Some commenters argue that RTO/ISO staff may be unable to
demonstrate independence in such a process. Conversely, Indicated NYTOs
argue that requiring RTO/ISO staff to act as decision-makers would
compromise their independence. In response to these concerns, and to
address the issue where the transmission owner is the transmission
provider outside of RTOs/ISOs, the LGIP provision adopted in this final
action requires transmission providers to appoint an independent third
party to preside over dispute resolution proceedings.
    150. In response to Generation Developers' contention that
interconnection customers should bear the fees for the decision-maker,
we find that it makes little sense to have one disputing party bear all
costs when there are multiple parties involved in the dispute. For this
reason, the newly adopted provision in section 13.5.5 of the pro forma
LGIP requires the same cost division as that established for the
arbitration process described in section 13.5 of the pro forma LGIP.
Thus, the cost of the decision-maker shall be divided equally among
each party to the dispute. Each individual party to a dispute will be
responsible for its own costs incurred during the process.
    151. The final action requires that the assigned decision-maker
have no ``current or past substantial business or financial
relationships with either party.'' We note that this standard is
identical to the neutrality standard proposed in the NOPR and to the
one established for arbitrators in section 13.5 of the pro forma LGIP.
While MISO argues that this standard would limit the pool of eligible
participants, we read MISO's comments to pertain to the NOPR proposal,
which required RTOs/ISOs to have RTO/ISO staff serve as decision-
makers. For this reason, the neutrality standard adopted in this final
action will not be too burdensome, in light of the changes from the
NOPR.
    152. With regard to NYISO's concern about ``outsourcing''
responsibility to subcontractors, we note that the newly created
process, like the arbitration process described in section 13.5 of the
pro forma LGIP, limits a decision-maker's authority so that it may only
``interpret and apply the provisions of the LGIA and LGIP.'' The
subcontractor would therefore have no ability to alter NYISO's existing
responsibilities.
e. Binding Nature of the Proposal
i. Comments
    153. AWEA indicates that, due to neutrality issues that are likely
to remain, dispute resolution should be non-binding.\261\ Similarly,
NextEra argues that it would not be appropriate for this ``expeditious
input'' to be binding on the parties and cause them to lose rights
under sections 205 or 206 of the FPA.\262\ NextEra also asserts that if
the expedited dispute resolution were binding, there would be too much
risk involved.\263\ NextEra views the process as similar to ``input
from a subject matter expert'' rather than any form of litigation.\264\
---------------------------------------------------------------------------

    \261\ AWEA 2017 Comments at 24.
    \262\ NextEra 2017 Comments at 16.
    \263\ Id.
    \264\ Id.
---------------------------------------------------------------------------

ii. Commission Determination
    154. In this final action, we adopt a non-binding dispute
resolution process. The pro forma LGIP provisions adopted in this final
action will be an alternative to, and not a replacement of, the
existing arbitration process described in section 13.5 of the pro forma
LGIP, which is a binding process. Specifically, section 13.5.3 of the
pro forma LGIP states that ``the decision of the arbitrator(s) shall be
final and binding upon the Parties, and judgment on the award may be
entered in any court having jurisdiction.'' \265\ Because the new
process adopted in this final action does not require mutual agreement,
we agree with AWEA and NextEra that this new process should be non-
binding.\266\ Although the non-binding nature of the process could
dampen its appeal, the process would still require disputing parties to
participate in a process presided over by a neutral party. To this
point, we agree with NextEra that the process would be beneficial
because it would offer an opportunity for ``input from a subject matter
expert.'' Additionally, we find that it would be inappropriate for the
new, non-binding dispute resolution process to limit a party's ability
to pursue a complaint pursuant to section 206 of the FPA.
---------------------------------------------------------------------------

    \265\ Pro forma LGIP Section 13.5.3 (emphasis added).
    \266\ No other commenters discussed this issue. Although we are
adopting a non-binding process in the pro forma LGIP, transmission
providers that have binding dispute resolution processes that, on
compliance, are able to demonstrate that their processes otherwise
satisfactorily adhere to the tenets of this final action (i.e., that
they do not require mutual agreement) may qualify for a variation
from the pro forma LGIP provision adopted in this final action.
---------------------------------------------------------------------------

f. Timing
i. Comments
    155. AWEA strongly supports the Commission's proposal to require
the RTO/ISO-devised dispute resolution procedures to account for the
interconnection process's time sensitivity.\267\ Generation Developers
argue that the proposed regulation fails to meaningfully address time
sensitivity and contends that the process could be resolved within 30
days of initiation.\268\ FTC argues that the proposed requirement that
RTOs/ISOs account for the time sensitivity of the generator
interconnection process is likely to reduce a transmission provider's
ability to delay interconnection dispute resolution.\269\ AVANGRID
comments that any dispute resolution procedures must not result in
``significant delay'' of the generator interconnection process.\270\
---------------------------------------------------------------------------

    \267\ AWEA 2017 Comments at 24-25.
    \268\ General Developers 2017 Comments at 19.
    \269\ FTC 2017 Comments at 10. See NOPR, FERC Stats. & Regs. ]
32,719 at P 87.
    \270\ AVANGRID 2017 Comments at 18.
---------------------------------------------------------------------------

    156. TDU Systems state that, for non-RTO/ISO regions, it would be
appropriate to reduce to two weeks the thirty-day period for parties to
resolve disputes once a formal notice of the dispute has been provided.
TDU Systems argue that nothing prevents the parties from continuing to
attempt to

resolve the dispute informally once other procedures are initiated, and
given the time sensitivity of these issues, a shorter timeframe would
be less prejudicial to the interconnection customer.\271\
---------------------------------------------------------------------------

    \271\ TDU Systems 2017 Comments at 12.
---------------------------------------------------------------------------

    157. TDU Systems state that the rules in section 13.5 of the pro
forma LGIP and article 27 of the pro forma LGIA provide for a thirty-
day period in which the parties will attempt to resolve a dispute,
followed by the right for the parties to mutually agree to submit the
dispute to arbitration; however, TDU Systems contend that the selection
of the arbitrator can take up to thirty days, with the arbitration
decision to be rendered within ninety days of appointment. TDU Systems
note that, in contrast, article 10 of the SGIA and section 4.2 of the
SGIP provide that if a dispute has not been resolved within two
business days after receipt of a notice of the dispute, either party
may contact FERC's Dispute Resolution Service for assistance in
resolving the dispute.
    158. TDU Systems ask the Commission to adopt fast-track complaint
procedures for complaints that parties cannot resolve or do not
mutually agree to arbitrate. It recommends a fixed period of time (for
example, sixty days) from complaint filing to Commission order
issuance. TDU Systems recognizes that even fast-track procedures, which
it estimates could result in order issuance twenty days from the filing
of an answer, might still be too long for interconnection disputes and
that there is no guarantee of fast-track procedures. TDU Systems ask
the Commission to specify that interconnection complaints are entitled
to fast-track complaint procedures if the Commission does not adopt a
separate streamlined interconnection process.\272\
---------------------------------------------------------------------------

    \272\ Id. at 13.
---------------------------------------------------------------------------

ii. Commission Determination
    159. The pro forma LGIP provision adopted in this final action
requires the appointment of a decision-maker within thirty days of the
receipt of a request for non-binding dispute resolution and requires a
decision within sixty days of the decision-maker's appointment. We note
that this process would require a decision thirty days sooner than the
arbitration process described in section 13.5 of the pro forma LGIP
would require. While the Commission did not propose such a timeline in
the NOPR, the Commission did express the view that any new dispute
resolution process should ``account for the time sensitivity of the
generator interconnection process.'' \273\ The timeline adopted here is
consistent with this position.
---------------------------------------------------------------------------

    \273\ NOPR, FERC Stats. & Regs. ] 32,719 at P 84.
---------------------------------------------------------------------------

    160. We disagree with TDU Systems' position that we should adopt
different timing requirements inside and outside RTOs/ISOs, and we
instead apply this rule generically. Additionally, while TDU Systems
point to the timing requirements in the pro forma SGIP dispute
resolution process, we note that, as discussed more fully below, we
decline to adopt the timing requirements in the pro forma SGIP dispute
resolution process for the pro forma LGIP. Finally, we disagree with
TDU Systems' request that we should require fast-track complaint
procedures for generator interconnection disputes. Because of the fact-
specific nature of every complaint, we do not support the request to
have fast-track complaint procedure for one category of disputes.
g. Mutual Agreement
i. Comments
    161. Multiple commenters support the elimination of the mutual
agreement requirement.\274\ MISO states that, while it does not oppose
this requirement, in MISO, parties to a generator interconnection
dispute can already commence dispute resolution unilaterally. MISO
further notes that, while a disputing party may exit its procedures at
certain designated points to pursue the Commission complaint process or
other remedies, no party can veto another party's ability to pursue
dispute resolution under the procedures.\275\ Similarly, PG&E believes
this reform is not applicable to CAISO because CAISO allows any
disputing party to trigger dispute resolution and does not require
agreement from a transmission owner or CAISO.\276\
---------------------------------------------------------------------------

    \274\ Generation Developers 2017 Comments at 16; EDP 2017
Comments at 5; Invenergy 2017 Comments at 15-16; FTC 2017 Comments
at 10; NEPOOL 2017 Comments at 8; NextEra 2017 Comments at 15; TDU
Systems 2017 Comments at 11; AVANGRID 2017 Comments at 18.
    \275\ MISO 2017 Comments at 17-18.
    \276\ PG&E 2017 Comments at 5 (citing CAISO Tariff, eTariff,
FERC Electric Tariff, OATT, app. DD, Section 15.5 (1.0.0)).
---------------------------------------------------------------------------

    162. EEI questions who should bear the costs for such unilateral
activity or how such costs would be recovered.\277\ EEI states that the
Commission has not explained how unilateral dispute resolution would
work because it implies a non-consensual process, which is more akin to
an adjudication.\278\ EEI is uncertain as to what authority an RTO/ISO
would or should have in this process and whether this proposal is
intended to limit a transmission provider's or interconnection
customer's right to seek judicial relief.\279\
---------------------------------------------------------------------------

    \277\ EEI 2017 Comments at 28.
    \278\ Id. at 27.
    \279\ Id.
---------------------------------------------------------------------------

    163. ISO-NE and EEI contend that, if the requirement for mutual
agreement for alternative resolution methods is removed, unnecessary
delays and uncertainties may result.\280\ ISO-NE argues that its
current dispute resolution process provides a disputing party with
recourse and minimizes the potential for unnecessary delays and
uncertainty by allowing for dispute resolution through a section 206
complaint filed with the Commission.\281\ As a result, ISO-NE states
that the current pro forma construct avoids disagreements being
submitted to arbitration, which would consume significant ISO-NE
resources.\282\
---------------------------------------------------------------------------

    \280\ ISO-NE 2017 Comments at 19; EEI 2017 Comments at 27.
    \281\ ISO-NE 2017 Comments at 19-20.
    \282\ Id. at 20-21.
---------------------------------------------------------------------------

ii. Commission Determination
    164. The provision adopted in this final action requires that
transmission providers allow disputing parties to unilaterally seek
dispute resolution procedures. In response to MISO and PG&E, we again
note that, to the extent MISO and CAISO believe that they comply with
the adopted pro forma LGIP provisions, they may explain their positions
in their compliance filings.
    165. We also clarify for EEI that, although each party will bear
its own costs to participate in the dispute resolution process, the
cost of the decision-maker will be split equally among the disputing
parties. Furthermore, we clarify for EEI that the process adopted by
this final action, unlike the arbitration process described in section
13.5 of the pro forma LGIP, is non-binding and thus does not limit a
party's right to seek judicial relief.
    166. In response to ISO-NE, we note that its concerns about delays
and uncertainty would still be present if disputing participants choose
to participate in the existing arbitration process described in section
13.5 of the pro forma LGIP. If transmission providers have agreed to
participate in an arbitration process pursuant to section 13.5, other
interconnection customers, including those in the same cluster as the
disputing interconnection customer would experience a delay.
Furthermore, as discussed above, multiple generation developers have
alleged that the section 13.5 arbitration process is effectively
unavailable to interconnection customers because

transmission providers are disinclined to participate. It will benefit
the interconnection process for there to be an available avenue of
dispute resolution to resolve a genuine matter of dispute.
    167. Additionally, in response to ISO-NE's argument that it avoids
delay by ``allowing for'' a section 206 complaint, we answer that the
pro forma LGIP already allows parties to file a complaint pursuant to
section 206 of the FPA, and this option is still available even if the
disputing parties mutually agree to the arbitration process described
in section 13.5 of the pro forma LGIP.\283\ Thus, we disagree with ISO-
NE that ``allowing for'' the process pursuant to section 206 is
sufficient to address our concerns with the status quo. The dispute
resolution provisions adopted in this final action serve as an
alternative to both the section 13.5 arbitration process and the FPA
section 206 process. With regard to ISO-NE's suggestion that the NOPR
proposal would consume significant ISO-NE resources, we note that the
final action distributes the costs of the decision-maker overseeing the
dispute resolution process equally among the parties to the dispute.
Thus, even though transmission providers must allow for a dispute
resolution process that a party may seek unilaterally, a transmission
provider would only be responsible for costs if it is a party to the
dispute. In such a scenario, the transmission provider would be
responsible ``for its own costs incurred'' during the process (i.e.,
the cost to represent its position in the section 13.5.5 dispute
resolution process) and the cost of the decision-maker ``divided
equally among each Party to the dispute.'' Thus, if a transmission
provider is not a party to a dispute, it would not be ultimately
responsible for any costs related to the dispute resolution process. If
the transmission provider is a party to a three party dispute, it would
be responsible for ``its own costs incurred'' and one-third of the cost
of the decision-maker.
---------------------------------------------------------------------------

    \283\ Order No. 2003, FERC Stats. & Regs. ] 31,146 at P 290
(stating that invocation of the arbitration process does not
``circumscribe[] the Parties' right to avail themselves of the
Commission's complaint process'').
---------------------------------------------------------------------------

h. SGIP DRS Process
i. Comments
    168. Competitive Suppliers argue that the Commission should
generically adopt the dispute resolution provisions of the pro forma
SGIP, which allow disputing parties to contact DRS.\284\ Similarly,
ISO-NE contends that, if the Commission determines that there is a need
to revise the existing pro forma LGIP and pro forma LGIA dispute
resolution provisions, then the Commission should adopt the same
approach provided for in the pro forma SGIP.\285\ TDU Systems also
contend that parties in non-RTO/ISO regions with disputes arising under
the LGIP and LGIA, like parties to the pro forma SGIA and pro forma
SGIP, should have the unilateral ability to seek DRS' assistance.\286\
For non-RTO/ISO regions, SEIA requests that the Commission clarify that
DRS is available to resolve interconnection disputes and will abide by
the same general structures as those proposed in the NOPR.\287\
---------------------------------------------------------------------------

    \284\ Competitive Suppliers 2017 Comments at 6.
    \285\ ISO-NE 2017 Comments at 19.
    \286\ TDU Systems 2017 Comments at 11-13.
    \287\ SEIA 2017 Comments at 14-15. We assume SEIA is referring
to DRS.
---------------------------------------------------------------------------

ii. Commission Determination
    169. In the NOPR, the Commission sought comment on ``the
appropriateness of adopting procedures similar to those outlined in the
pro forma SGIP.'' \288\ The process described in section 4.2 of the pro
forma SGIP allows parties to contact DRS for assistance in resolving an
interconnection dispute. Section 4.2.4 of the pro forma SGIP states
that DRS will assist in resolving a dispute or in selecting an
appropriate dispute resolution venue. Additionally, section 4.2.6 of
the pro forma SGIP states that if neither party elects to contact DRS
or if the attempted dispute resolution fails, ``either Party may
exercise whatever rights and remedies it may have in equity or law
consistent with the terms of these procedures.''
---------------------------------------------------------------------------

    \288\ NOPR, FERC Stats. & Regs. ] 32,719 at P 86.
---------------------------------------------------------------------------

    170. In response to the Commission's request for comments, only
Competitive Suppliers and ISO-NE commented favorably in response to
this suggestion. For this reason, we decline to take action to adopt
dispute resolution procedures similar to those in the pro forma SGIP.
Nonetheless, nothing in this final action precludes disputing parties
from contacting DRS if they wish to participate in dispute resolution
through that avenue.
    171. In response to SEIA, we note that, consistent with Order No.
2003, DRS is always available to assist parties in resolving generator
interconnection disputes. We note, however, that the new requirements
imposed by this final action apply only to the non-binding dispute
resolution process established through new section 13.5.5 in the pro
forma LGIP, which is a non-DRS process.
5. Capping Costs for Network Upgrades
a. NOPR Request for Comments
    172. As part of the interconnection feasibility study and system
impact study, the pro forma LGIP requires that transmission providers
provide a good faith estimate of the cost of interconnection facilities
and network upgrades needed to accommodate an interconnection
customer's requested level of interconnection service.\289\ The
transmission provider includes this cost estimate with the facilities
study results, typically with a stated accuracy margin within 10 to 20
percent of the estimate.\290\ After completion of the construction of
the transmission provider's interconnection facilities and network
upgrades needed to interconnect a generating facility, the transmission
provider conducts a true-up to assess the final cost of construction to
the interconnection customer. The transmission provider provides a
final invoice to the interconnection customer that details variations
between actual and estimated costs. Overpayment by the interconnection
customer results in a refund to the interconnection customer, or a
surcharge in case of an underpayment.\291\
---------------------------------------------------------------------------

    \289\ See, e.g., pro forma LGIP Sections 6.2 and 7.3.
    \290\ Pro forma LGIP Section 8.3.
    \291\ Pro forma LGIA Art. 12.
---------------------------------------------------------------------------

    173. The Commission sought comment on whether it should revise the
pro forma LGIP and pro forma LGIA to provide for a cost cap that would
limit an interconnection customer's network upgrade costs at the higher
bound of a transmission provider's cost estimate plus a stated accuracy
margin following a certain stage in the interconnection study process.
Such a cap could permit the interconnection customer to assume costs
that exceed the cap under limited circumstances, such as where there is
demonstrable proof that the cause of a cost increase is beyond the
transmission provider's control.\292\ The cost cap could also specify
which party or parties would assume network upgrade costs in excess of
the cap. The Commission further sought comment on how to minimize
potential cost shifts to other parties if such a cost cap is imposed.
The Commission also sought comments on alternative proposals, or
additional steps that the Commission could take, to provide more cost
certainty to

interconnection customers during the interconnection study
process.\293\
---------------------------------------------------------------------------

    \292\ NOPR, FERC Stats. & Regs. ] 32,719 at P 95.
    \293\ Id.
---------------------------------------------------------------------------

b. Comments
    174. A minority of commenters,\294\ primarily renewable generation
developers and transmission owners in CAISO, support the idea of
network upgrade cost caps. AWEA notes that interconnection customers
often pay costs that exceed the upper bound of a transmission
provider's estimates, and this can significantly disrupt an
interconnection customer's business model.\295\ AWEA argues that a cost
cap would protect interconnection customers from cost overruns, allow
them to accurately assess risk, and reduce the number of late-stage
withdrawals due to increased cost certainty, which in turn would
produce more accurate cost estimates.\296\ AWEA, Generation Developers,
and NextEra assert that the imposition of a cost cap should incentivize
more accurate cost estimates, and AWEA contends that cost shifts should
be minimal if the transmission provider estimates costs more
accurately.\297\
---------------------------------------------------------------------------

    \294\ These commenters include: AWEA 2017 Comments at 26; CAISO
2017 Comments at 13; First Solar 2017 Comments at 4; Joint Renewable
Parties 2017 Comments at 3; Generation Developers 2017 Comments at
22-23; EDP 2017 Comments at 5-6; NextEra 2017 Comments at 17' and
PG&E 2017 Comments at 5.
    \295\ AWEA 2017 Comments at 25.
    \296\ Id. at 25-26.
    \297\ Id. at 27; Generation Developers 2017 Comments at 23-24;
NextEra 2017 Comments at 17-19.
---------------------------------------------------------------------------

    175. Generation Developers argue that if there is an overage from
the cost estimate, it is just and reasonable to socialize that overage.
Generation Developers acknowledge that this is a variation from strict
``but for'' interconnection policy but assert that the variation is
justified because all users of the transmission network receive
benefits from the interconnection customer's network upgrades.
    176. APS, AVANGRID, Bonneville, EDP, Generation Developers,
Invenergy, MISO TOs, NextEra, NorthWestern, and Tri-State contend that
cost caps could lead to inflated cost estimates for network
upgrades.\298\ On the other hand, commenters that support cost caps
argue that increased cost estimates can either be addressed or are a
reasonable trade-off for implementing a cost cap.\299\
---------------------------------------------------------------------------

    \298\ APS 2017 Comments at 3; AVANGRID 2017 Comments at 20;
Bonneville 2017 Comments at 3; EDP 2017 Comments at 5; Generation
Developers 2017 Comments at 24; Invenergy 2017 Comments at 9; MISO
TOs 2017 Comments at 10-11; NextEra 2017 Comments at 17;
NorthWestern 2017 Comments at 4; Tri-State 2017 Comments at 5.
    \299\ Generation Developers 2017 Comments at 24, AWEA 2017
Comments at 27, and NextEra 2017 Comments at 18.
---------------------------------------------------------------------------

    177. CAISO states that, while cost caps come with some risk, they
allow generators to have clear demarcations for their financial
responsibilities going forward, which CAISO believes mitigates risk and
financial uncertainty when generators submit proposals to provide
capacity and later seek financing for construction.\300\
---------------------------------------------------------------------------

    \300\ CAISO 2017 Comments at 13.
---------------------------------------------------------------------------

    178. Most responsive commenters \301\ oppose revising the pro forma
LGIP and pro forma LGIA to impose network upgrade cost caps. Several
opposing commenters argue that cost caps would unfairly shift network
upgrade costs from interconnection customers to load, transmission
customers, or other interconnection customers that neither benefit from
the generation nor caused the need for the upgrades.\302\ Several
commenters also assert that cost caps would violate the Commission's
``but for'' and cost causation policies for the assignment of
interconnection network upgrade costs.\303\ Duke, EEI, and NorthWestern
contend that if the Commission establishes a cost cap and requires that
transmission providers assume any excess costs, transmission providers
could face challenges of whether such costs are prudent transmission
investments.\304\ EEI, Non-Profit Utility Trade Associations, and TAPS
argue that implementing cost caps will likely result in more frequent
and contentious litigation.\305\
---------------------------------------------------------------------------

    \301\ Alliant 2017 Comments at 5; AEP 2017 Comments at 3; AFPA
2017 Comments at 5; AVANGRID 2017 Comments at 19; Bonneville 2017
Comments at 3; Competitive Suppliers 2017 Comments at 7; Duke 2017
Comments at 7; EEI 2017 Comments at 28; ELCON 2017 Comments at 2;
Eversource 2017 Comments at 12; Imperial 2017 Comments at 18;
IECA2017 Comments at 2; ISO-NE 2017 Comments at 21; ITC 2017
Comments at 12-13; MidAmerican 2017 Comments at 11-12; MISO 2017
Comments at 21; MISO TOs 2017 Comments at 7; Modesto 2017 Comments
at 18; NEPOOL 2017 Comments at 9; Non-Profit Utility Trade
Associations 2017 Comments at 6; NorthWestern 2017 Comments at 4;
NYISO 2017 Comments at 19; PJM 2017 Comments at 9; PSEG/PPL 2017
Comments at 3; Salt River 2017 Comments at 9; Southern 2017 Comments
at 15-16; TAPS 2017 Comments at 3; TDU Systems 2017 Comments at 14-
16; Tri-State 2017 Comments at 5; TVA 2017 Comments at 6-7; Xcel
2017 Comments at 11.
    \302\ Alliant 2017 Comments at 6; AEP 2017 Comments at 3; Duke
2017 Comments at 7; EEI 2017 Comments at 29; ELCON 2017 Comments at
2,5; Idaho Power 2017 Comments at 2-3; Imperial 2017 Comments at 19;
IECA 2017 Comments at 2; ISO-NE 2017 Comments at 22; MidAmerican
2017 Comments at 11-12; MISO 2017 Comments at 21; MISO TOs 2017
Comments at 7; Modesto 2017 Comments at 19; Non-Profit Utility Trade
Associations 2017 Comments at 6; NorthWestern 2017 Comments at 4;
PJM 2017 Comments at 10; PSEG/PPL 2017 Comments at 5; Salt River
2017 Comments at 9; Southern 2017 Comments at 15-16; TAPS 2017
Comments at 5; TDU Systems 2017 Comments at 14-16; TVA 2017 Comments
at 6-7.
    \303\ AEP 2017 Comments at 5; AVANGRID 2017 Comments at 20; EEI
2017 Comments at 28-29; ITC 2017 Comments at 12-13; MISO 2017
Comments at 21; MISO TOs 2017 Comments at 7; PJM 2017 Comments at 9-
10; PSEG/PPL 2017 Comments at 5; Salt River 2017 Comments at 9;
Southern 2017 Comments at 15-16; TAPS 2017 Comments at 6; TDU
Systems 2017 Comments at 14-16; TVA 2017 Comments at 6-7.
    \304\ Duke 2017 Comments at 7-8; EEI 2017 Comments at 29-30;
NorthWestern 2017 Comments at 4.
    \305\ EEI 2017 Comments at 33-34; Non-Profit Utility Trade
Associations 2017 Comments at 11; TAPS 2017 Comments at 7.
---------------------------------------------------------------------------

    179. Modesto argues that because smaller entities do not frequently
estimate interconnection facility and network upgrade costs, their cost
estimates are likely susceptible to greater variability, which could
lead to a greater inaccuracy. Modesto asserts that smaller entities
essentially would be penalized through cost caps on network
upgrades.\306\
---------------------------------------------------------------------------

    \306\ Modesto 2017 Comments at 19-20.
---------------------------------------------------------------------------

    180. Several commenters contend that cost caps are unwarranted
because many of the variables that affect cost estimates are outside
the transmission provider's control and are based on the best data
available at the time.\307\ AFPA argues that cost caps remove risk from
interconnection customers and may remove the incentive for
interconnection customers to mitigate cost overruns in network
upgrades.\308\ IECA expresses concern that industrial consumers will
have to pay for cost overruns resulting from a cost cap and that cost
caps would encourage developers and utilities to be equally complacent
about cost overruns.\309\
---------------------------------------------------------------------------

    \307\ AEP 2017 Comments at 3; Duke 2017 Comments at 7; EEI 2017
Comments at 30-32; ITC 2017 Comments at 14-15; MidAmerican 2017
Comments at 12; MISO 2017 Comments at 21; MISO TOs 2017 Comments at
10-11; PSEG/PPL 2017 Comments at 5; Salt River 2017 Comments at 9;
Southern 2017 Comments at 16; Tri-State 2017 Comments at 5.
    \308\ AFPA 2017 Comments at 9.
    \309\ IECA 2017 Comments at 2.
---------------------------------------------------------------------------

    181. ITC, MISO, Non-Profit Utility Trade Associations, and Xcel
state that well-defined milestones and milestone payments are
preferable to a cost cap.\310\
---------------------------------------------------------------------------

    \310\ ITC 2017 Comments at 15; MISO 2017 Comments at 22-23; Non-
Profit Utility Trade Associations 2017 Comments at 1-2, 4, 10-11;
Xcel 2017 Comments at 12.
---------------------------------------------------------------------------

    182. NYISO and Indicated NYTOs state that NYISO already has a
process in place in its tariff to allocate actual costs that exceed
cost estimates.\311\ Indicated NYTOs contend that NYISO's provisions
encourage interconnection

customers to efficiently locate their generating facility and strike a
reasonable balance between providing certainty to interconnection
customers and minimizing the imposition of unnecessary costs to
load.\312\ NYISO asserts that adoption of bright line cost caps would
likely require more detailed studies, cost estimates, and increased
cost and time, contrary to the stated principles of the NOPR.\313\
NEPOOL notes that New England resolved its disputes over cost
allocation for interconnections and regional transmission upgrades well
over a decade ago through the interconnection cost allocation method in
the ISO-NE OATT.\314\
---------------------------------------------------------------------------

    \311\ NYISO 2017 Comments at 19; Indicated NYTOs 2017 Comments
at 5.
    \312\ Indicated NYTOs 2017 Comments at 6.
    \313\ NYISO 2017 Comments at 19.
    \314\ NEPOOL 2017 Comments at 9.
---------------------------------------------------------------------------

    183. Salt River and TVA believe that it would be inappropriate for
the Commission to attempt to impose a cap on the costs that can be
collected by a not-for-profit governmental utility, via the reciprocity
condition or otherwise.\315\
---------------------------------------------------------------------------

    \315\ Salt River 2017 Comments at 10; TVA 2017 Comments at 6-7.
---------------------------------------------------------------------------

    184. CAISO states that its system of cost caps may be more
difficult to implement outside of regions where ratepayers ultimately
pay for generator interconnection-driven network upgrades.\316\ CAISO
notes that, in CAISO, the interconnection customer only provides the
initial financing for its network upgrades.\317\ CAISO states that,
upon reaching commercial operation, those costs are reimbursed by the
transmission owner and included in that transmission owner's
transmission revenue requirement paid by ratepayers.\318\
---------------------------------------------------------------------------

    \316\ CAISO 2017 Comments at 14.
    \317\ Id.
    \318\ Id.
---------------------------------------------------------------------------

    185. AFPA, ELCON, ITC, SEIA, and Invenergy assert that policies
other than cost caps will provide greater downward pressure on network
upgrade costs including improving cost transparency, transmission
planning that anticipates future generation needs, and aligning
interconnection procedures with resource procurement processes.\319\
---------------------------------------------------------------------------

    \319\ AFPA 2017 Comments at 5; ELCON 2017 Comments at 5; ELCON
2017 Comments at 5; ITC 2017 Comments at 15; SEIA 2017 Comments at
15; Invenergy 2017 Comments at 9-10.
---------------------------------------------------------------------------

    186. Eversource suggests that the Commission instead explore the
transmission provider's cost estimation process.\320\ Eversource
suggests that, to improve cost estimates, the Commission should require
interconnection customers to use the currently optional facilities
study in the LGIP.\321\
---------------------------------------------------------------------------

    \320\ Eversource 2017 Comments at 13-14.
    \321\ Id. at 15.
---------------------------------------------------------------------------

    187. Xcel recommends that, instead of imposing cost caps, the
Commission should reevaluate its policy discussed in Order No. 2003 and
implement regional variations that allow transmission costs to be
assigned to the interconnection customer after the execution of an
LGIA.\322\ Xcel further recommends limiting the interconnection
customer's cost responsibility to the specific facilities identified in
the signed LGIA, rather than allowing the RTO/ISO, as transmission
provider, to later modify the list of required facilities. Xcel asserts
that if facilities are identified after the interconnection customer
and transmission provider sign an LGIA, the costs of those facilities
should be recovered from transmission customers through the
transmission expansion cost allocation processes in the RTO/ISO tariff.
Xcel believes that the Commission should allow regions to determine if
or when such costs are allocated either locally or regionally to
transmission customers.\323\
---------------------------------------------------------------------------

    \322\ Xcel 2017 Comment at 12.
    \323\ Id. at 12-13.
---------------------------------------------------------------------------

    188. TAPS opposes a generic rule establishing a cost cap and also
opposes a generic rule that bars all cost caps.\324\ Duke states that
transmission providers should be able to voluntarily adopt cost caps if
done so through stakeholder processes.\325\
---------------------------------------------------------------------------

    \324\ TAPS 2017 Comments at 8.
    \325\ Duke 2017 Comments at 8.
---------------------------------------------------------------------------

c. Commission Determination
    189. In this final action, we decline to take any action related to
capping costs for network upgrades. We find that there is insufficient
evidence in the record to support cost caps as a preferred solution to
reducing variances from cost estimates and providing greater cost
certainty to interconnection customers. Therefore, we decline to
propose revisions to the pro forma LGIP and pro forma LGIA to institute
a cap on the cost of network upgrades required for interconnection.
However, as suggested by Duke, we will not bar a transmission provider
from proposing to establish cost caps for network upgrade costs within
its footprint by submitting a separate filing pursuant to section 205
of the FPA.
    190. We recognize the value of providing more accurate cost
estimates to interconnection customers of the network upgrades needed
to interconnect their generating facilities. Smaller deviations between
the cost estimate and the final costs of the network upgrades would
reduce risk and uncertainty faced by the interconnection customer. We
note that other actions in this final action, including the reforms on
transparency regarding study models and assumptions and identification
and definition of contingent facilities, could contribute to improved
accuracy of cost estimates for network upgrades. Additionally, we
understand that greater cost certainty, where reasonably achievable
without creating overly onerous requirements, could reduce queue
withdrawals and their cascading effects on other projects within the
queue. We encourage transmission providers and stakeholders to continue
to work together to improve the cost estimation process.

B. Promoting More Informed Interconnection

    191. In the NOPR, the Commission proposed reforms designed to
improve interconnection process transparency and provide improved
information to benefit all participants in the interconnection process.
In addition to the proposed reforms, the Commission sought comment on
proposals or additional steps that the Commission could take to improve
the resolution of issues that arise when affected systems are impacted
by a proposed interconnection.
1. Identification and Definition of Contingent Facilities
a. NOPR Proposal
    192. The Commission currently requires transmission providers to
identify for interconnection customers contingencies affecting
interconnection studies \326\ and list applicable contingent facilities
in interconnection agreements.\327\ In the NOPR, the Commission
proposed to revise the pro forma LGIP to require transmission providers
to detail the methods they use to determine which facilities are
contingent facilities. The Commission proposed that a method be
transparent and sufficiently detailed to allow interconnection
customers to determine why a specific contingent facility is included
and how it impacts the interconnection request. The Commission also
proposed that

transmission providers provide the contingent facility list at the
conclusion of the system impact study. The Commission further proposed
that the transmission provider should, upon request, provide the
estimated network upgrade costs and in-service completion time
associated with each identified contingent facility when this
information is not commercially sensitive. In particular, the
Commission proposed to add a new section 3.8 to the pro forma LGIP as
follows (with proposed additions in italics):
---------------------------------------------------------------------------

    \326\ Pro forma LGIP Section 2.3.
    \327\ Order No. 2003, FERC Stats. & Regs. ] 31,146 at P 409
(``[i]f it is apparent to the Parties . . . that contingencies (such
as other Interconnection Customers terminating their LGIAs) might
affect the financial arrangements, the Parties should include such
contingencies in their LGIA and address the effect of such
contingencies on their financial obligations'').

    3.8 Identification of Contingent Facilities
    Transmission Provider shall post in this section a method for
identifying the Contingent Facilities to be provided to
Interconnection Customer at the conclusion of the System Impact
Study and included in Interconnection Customer's GIA. The method
shall be sufficiently transparent to determine why a specific
Contingent Facility was identified and how it relates to the
interconnection request. Transmission Provider shall also provide,
upon request of the Interconnection Customer, the estimated
interconnection facility and/or network upgrade costs and estimated
in-service completion time of each identified Contingent Facility
when this information is not commercially sensitive.

    193. In addition, the Commission proposed to add the following new
definition to section 1 of the pro forma LGIP (with proposed additions
in italics):

    Contingent Facilities shall mean those unbuilt interconnection
facilities and network upgrades upon which the interconnection
request's costs, timing, and study findings are dependent, and if
not built, could cause a need for interconnection restudies or
reassessments of the network upgrades, costs, or timing.

    194. The Commission also sought further comment on how transmission
providers currently identify contingent facilities, as well as
additional recommendations to improve the existing approach. Finally,
the Commission sought comment on whether the method for determining
contingent facilities should be harmonized as much as possible. To this
end, the Commission sought comment on the usefulness of requiring
transmission providers to include a distribution factor analysis in
their methodologies for identifying contingent facilities, and if so,
whether a specific distribution factor should be implemented in the pro
forma LGIP (e.g., a five percent distribution factor).
b. General
i. Comments
    195. Most responsive commenters support \328\ or do not oppose
\329\ the proposal to require transmission providers to publish a
method for identifying contingent facilities in the LGIP. Several
commenters state that the proposal will better inform the
interconnection process and may lead to lower costs and fewer
withdrawals.\330\ AWEA, Invenergy, and EDP cite inconsistent or non-
transparent treatment of contingent facilities across regions.\331\
Several commenters assert that the proposal will reduce opportunities
for undue discrimination and disputes.\332\
---------------------------------------------------------------------------

    \328\ Alevo 2017 Comments at 5-6; AFPA 2017 Comments at 10; Non-
Profit Utility Trade Associations 2017 Comments at 12-13; AWEA 2017
Comments at 30; Bonneville 2017 Comments at 4; Joint Renewable
Parties 2017 Comments at 10; Generation Developers at 25; SEIA 2017
Comments at 7; Portland 2017 Comments at 2; NEPOOL 2017 Comments at
9-10; NextEra 2017 Comments at 20; ITC 2017 Comments at 16;
Invenergy 2017 Comments at 11.
    \329\ MISO TOs 2017 Comments at 26; Non-Profit Utility Trade
Associations 2017 Comments at 12.
    \330\ AFPA 2017 Comments at 10; AWEA 2017 Comments at 30; NEPOOL
2017 Comments at 10; NextEra 2017 Comments at 20; Invenergy 2017
Comments at 12; EDP 2017 Comments at 6.
    \331\ EDP 2017 Comments at 6; AWEA 2017 Comments at 29;
Invenergy 2017 Comments at 11.
    \332\ AFPA 2017 Comments at 10; EDP 2017 Comments at 6; AWEA
2017 Comments at 31; Invenergy 2017 Comments at 11.
---------------------------------------------------------------------------

    196. AWEA and NextEra contend that the proposal will place a
minimal burden on transmission providers.\333\ ISO-NE comments that the
proposal appropriately balances the need for regional flexibility to
maintain the existing methods with the need to improve transparency
regarding the interconnection process.\334\ CAISO states that
information on contingent facilities is important to inform an
interconnection customer about potential delays that might necessitate
renegotiation of the interconnection customer's power purchase
agreement. NextEra supports the Commission's guidance that a
transmission provider's method to determine contingent facilities be
detailed and states that an unverified list of contingent facilities
creates uncertainty regarding potential restudies and revised cost
responsibility for the interconnection customer.\335\
---------------------------------------------------------------------------

    \333\ AWEA 2017 Comments at 31; NextEra 2017 Comments at 21.
    \334\ ISO-NE 2017 Comments at 25.
    \335\ NextEra 2017 Comments at 20.
---------------------------------------------------------------------------

    197. AWEA comments that the interconnection customer should not be
financially responsible for any facilities that are not listed among
the contingent facilities and that even contingent facilities omitted
in error should not be the financial responsibility of the
interconnection customer.\336\
---------------------------------------------------------------------------

    \336\ AWEA 2017 Comments at 34
---------------------------------------------------------------------------

    198. A minority of responsive commenters oppose the proposal.\337\
MISO and Southern request that the Commission permit transmission
providers to post the proposed information in their business practice
manuals or OASIS-posted business practices rather than in the LGIP, as
this information is technical and more suitable for a business practice
manual and may need frequent changes to address characteristics of new
technologies.\338\ Several commenters state that no new procedures are
necessary to identify and define contingent facilities.\339\
---------------------------------------------------------------------------

    \337\ Modesto 2017 Comments at 21; Southern 2017 Comments at 19;
EEI 2017 Comments at 38.
    \338\ MISO 2017 Comments at 24-25; Southern 2017 Comments at 19.
    \339\ AES 2017 Comments at 8-9; Southern 2017 Comments at 19.
---------------------------------------------------------------------------

ii. Commission Determination
    199. We adopt the NOPR proposal to add a new section 3.8 to the pro
forma LGIP requiring transmission providers to publish a method for
identifying contingent facilities in their LGIPs subject to
clarification as outlined below. Specifically, the Commission adds
section 3.8 to the pro forma LGIP as follows (with clarifying additions
to the language originally proposed in the NOPR in italics):

3.8 Identification of Contingent Facilities

    Transmission Provider shall post in this section a method for
identifying the Contingent Facilities to be provided to
Interconnection Customer at the conclusion of the System Impact
Study and included in Interconnection Customer's GIA. The method
shall be sufficiently transparent to determine why a specific
Contingent Facility was identified and how it relates to the
interconnection request. Transmission Provider shall also provide,
upon request of the Interconnection Customer, the estimated
interconnection facility and/or network upgrade costs and estimated
in-service completion time of each identified Contingent Facility
when this information is readily available and not commercially
sensitive.

    200. We note that commenters widely support the adoption of this
requirement. We agree with commenters that this requirement will
increase transparency in the interconnection process, better inform
interconnection customers, and, consequently, result in fewer
interconnection disputes and withdrawals. The Commission notes that,
while some transmission providers may provide information on contingent

facilities, the record indicates that this information may not be
available from all transmission providers. We find that requiring
transmission providers to publish a method for determining contingent
facilities in the LGIP will ensure that there will be a transparent
method applied on a non-discriminatory basis across all regions. We
also disagree with MISO's and Southern's arguments that it would be
more appropriate to publish methods for identifying contingent
facilities in business practice manuals or on OASIS. The Commission's
``rule of reason'' policy \340\ requires provisions that significantly
affect rates, terms, and conditions should be in the filed tariff.\341\
The Commission finds, based on the record above, that information on
contingent facilities materially affects rates, terms, and conditions,
and therefore, needs to be part of the tariff. However, while
transmission providers will have to publish their methods in the LGIP,
certain technical implementation details relating to the methods that,
consistent with the rule of reason, have less direct effect on rates,
terms and conditions, may be published in a business practice manual.
---------------------------------------------------------------------------

    \340\ See Pacificorp, 127 FERC ] 61,144, at P 11 (2009); City of
Cleveland, Ohio v. FERC, 773 F.2d 1368, 1376 (D.C. Cir. 1985)
(finding that utilities must file ``only those practices that affect
rates and service significantly, that are reasonably susceptible of
specification, and that are not so generally understood in any
contractual arrangement as to render recitation superfluous'');
Public Serv. Comm'n of N.Y. v. FERC, 813 F.2d 448, 454 (D.C. Cir.
1987) (holding that the Commission properly excused utilities from
filing policies or practices that dealt with only matters of
``practical insignificance'' to serving customers).
    \341\ Cal. Indep. Sys. Operator Corp. 119 FERC ] 61,076, at P
656 (2007) (citing ANP Funding I, LLC v. ISO-NE, Inc., 110 FERC ]
61,040, at P 22 (2005); Prior Notice and Filing Requirements Under
Part II of the Federal Power Act, 64 FERC ] 61,139, at 61,986-89,
order on reh'g, 65 FERC ] 61,081 (1993)).
---------------------------------------------------------------------------

    201. We disagree with AWEA's argument that the final action should
exempt the interconnection customer from financial responsibility for
any facilities that are not identified as contingent facilities,
because changes in the interconnection queue may require changes to or
subtractions from the list of contingent facilities. Thus, we find that
the final action strikes the right balance to accomplish our goal of
increasing transparency.
c. Timing
i. Comments
    202. Several commenters support the proposal that transmission
providers provide the list of contingent facilities applicable to an
interconnection request at the close of the system impact study
phase.\342\ AWEA comments that the timing for the identification of
contingent facilities has been a major issue for interconnection
customers. It argues that, currently, interconnection customers only
receive relevant contingent facility information after signing an LGIA.
AWEA asserts that the timing requirements in this proposal remove risk
for the interconnection customer.\343\
---------------------------------------------------------------------------

    \342\ AWEA 2017 Comments at 31; Duke 2017 Comments at 8;
Generation Developers 2017 Comments at 25; MISO 2017 Comments at 25-
26; TDU Systems 2017 Comments at 26.
    \343\ AWEA 2017 Comments at 31.
---------------------------------------------------------------------------

    203. MISO requests that the Commission clarify that, in the context
of MISO's phased system impact study process, the requirement would
apply only after the final system impact study.\344\
---------------------------------------------------------------------------

    \344\ MISO 2017 Comments at 26.
---------------------------------------------------------------------------

ii. Commission Determination
    204. We adopt the NOPR proposal to require transmission providers
to provide the list of contingent facilities applicable to an
interconnection request at the close of the system impact study phase.
The system impact study considers generating facilities and identified
network upgrades associated with higher-queued interconnection
requests, and an accompanying list of contingent facilities can
contextualize these results. We find that this timing allows
interconnection customers to access contingent facility information
early enough to better understand their potential risk exposure and to
expedite decisions on queue withdrawal, resulting in a more efficient
interconnection process. We note that the majority of responsive
commenters support the requirement to provide contingent facility
information at the conclusion of the system impact study phase. In
response to MISO's request that we address how the final action applies
to its system impact study process, we will evaluate each transmission
provider's tariff provisions at the time that it submits its compliance
filing. In that filing, MISO can explain how its compliance proposal
allows for the interconnection customer to use contingent facilities
information to understand risk exposure and expedite decisions on queue
withdrawal.
d. Requirements for Estimated Network Upgrade Costs and In-Service
Completion Times
i. Comments
    205. A majority of responsive commenters support the proposed
requirement to provide the costs and in-service completion time for
each identified contingent facility.\345\ AWEA states that
interconnection customers use information about potential cost
increases, as well as timing of necessary upgrades, to make business
decisions and assess risk.\346\ Generation Developers explain that
there is little value in identifying a contingent facility if the
interconnection customer still has no information about its associated
costs and timing.\347\ AWEA contends that non-disclosure agreements can
address commercial sensitivities related to contingent facilities.\348\
Invenergy states that PJM, MISO, and SPP already provide this
information in some form and that it is unaware of any commercially
sensitive information that would need to be revealed in this
process.\349\ Other commenters state that the burden on transmission
providers would be minimal.\350\
---------------------------------------------------------------------------

    \345\ AWEA 2017 Comments at 32; Alevo 2017 Comments at 5-6;
Forecasting Coalition 2017 Comments at 4; Generation Developers 2017
Comments at 26; TDU Systems 2017 Comments at 16-17; NEPOOL 2017
Comments at 10; NextEra 2017 Comments at 20; SEIA 2017 Comments at
7.
    \346\ AWEA 2017 Comments at 32.
    \347\ Generation Developers 2017 Comments at 26.
    \348\ AWEA 2017 Comments at 32.
    \349\ Invenergy 2017 Comments at 12.
    \350\ NextEra 2017 Comments at 20; AWEA 2017 Comments at 32.
---------------------------------------------------------------------------

    206. Duke, MidAmerican, and EEI oppose the proposed requirement to
provide estimated network upgrade costs and in-service completion times
for each identified contingent facility.\351\ EEI argues that the
Commission should address concerns related to potential commercially-
sensitive information and Critical Energy/Electric Infrastructure
Information (CEII). It asks the Commission to clarify that transmission
providers need not disclose proprietary, commercially-sensitive, or
CEII information without the appropriate consent and/or non-disclosure
protections.\352\ EEI also has concerns about the proposal's costs and
the appropriate recovery mechanisms.\353\ Duke states that schedules
and cost estimates for milestones are available on OASIS via links to
completed generator interconnection studies.\354\
---------------------------------------------------------------------------

    \351\ Duke 2017 Comments at 9-10; MidAmerican 2017 Comments at
8; EEI 2017 Comments at 38.
    \352\ EEI 2017 Comments at 39.
    \353\ Id.
    \354\ Duke 2017 Comments at 8.
---------------------------------------------------------------------------

    207. A number of commenters state that some or all of the
information referenced in the proposal is already made available in
their region. ISO-NE states that estimated costs and in-service
completion times associated with contingent facilities are available in
the

interconnection study reports for the higher-queued projects that are
primarily responsible for the cost of the contingent facility, and
those reports are available to interconnection customers on the ISO-NE
website.\355\ Bonneville states that it provides general estimates and
schedules associated with contingent facilities in its study
reports.\356\ MISO states that it already provides the estimated
network upgrade costs and in-service completion time of each identified
contingent facility via its MISO Transmission Expansion Plan process,
updated quarterly and posted publicly.\357\ MidAmerican comments that
it sees no value in providing this information and expresses concern
about the potential administrative burden.\358\
---------------------------------------------------------------------------

    \355\ ISO-NE 2017 Comments at 24.
    \356\ Bonneville 2017 Comments at 4.
    \357\ MISO 2017 Comments at 25.
    \358\ MidAmerican 2017 Comments at 8.
---------------------------------------------------------------------------

    208. TVA comments that it is difficult to estimate the in-service
timing of contingent facilities in the system impact study phase, as
often the full scope of work is not known until the facilities
study.\359\ TVA adds that to provide this information at the system
impact study phase would increase the cost and duration of all system
impact study efforts.\360\
---------------------------------------------------------------------------

    \359\ TVA 2017 Comments at 8.
    \360\ Id.
---------------------------------------------------------------------------

    209. Several commenters suggest that the Commission modify or
clarify this aspect of the proposal. NextEra suggests clarifying the
proposal to limit the information the transmission provider provides to
the interconnection customer based on what the transmission provider
could reasonably access so that transmission providers need not obtain
information that they may not readily have available.\361\ Similarly,
while Portland does not object to this aspect of the proposal, it
argues that such information would be limited to the best information
that the transmission provider has access to at the time.\362\
---------------------------------------------------------------------------

    \361\ NextEra 2017 Comments at 20.
    \362\ Portland 2017 Comments at 3.
---------------------------------------------------------------------------

    210. Forecasting Coalition and Alevo suggest that the transmission
provider provide additional information to the interconnection
customer. Alevo suggests that transmission providers also provide ``a
detailed list of the symptoms that the transmission owner/operator is
trying to cure.'' \363\ Alevo comments that this information may allow
the interconnection customer to offer a more cost-effective solution
(e.g., installing electric storage rather than building a new
substation).\364\ Forecasting Coalition requests that the transmission
provider identify the facility's limiting element along with the
details on the electrical limiting element's rating.\365\
---------------------------------------------------------------------------

    \363\ Alevo 2017 Comments at 5-6.
    \364\ Id.
    \365\ Forecasting Coalition 2017 Comments at 4.
---------------------------------------------------------------------------

    211. AWEA and Generation Developers argue that the transmission
provider should have to provide information on each identified
contingent facility's estimated costs and timing even if the
interconnection customer has not explicitly requested it.\366\
---------------------------------------------------------------------------

    \366\ AWEA 2017 Comments at 31-32; Generation Developers 2017
Comments at 25-26.
---------------------------------------------------------------------------

ii. Commission Determination
    212. We adopt the NOPR proposal, subject to modification, and
require the transmission provider to provide, upon request of the
interconnection customer, the estimated network upgrade costs and
estimated in-service completion time associated with each identified
contingent facility when this information is readily available \367\
and not commercially sensitive. We are persuaded by comments that
contend that this information helps interconnection customers to better
assess the business risks associated with contingent facilities and may
prevent instances of late-stage withdrawal. We find that these
benefits, in turn, lead to a more efficient and informed
interconnection process.
---------------------------------------------------------------------------

    \367\ In Order No. 792, the Commission defined ``readily
available'' information as ``information that the [t]ransmission
[p]rovider currently has on hand,'' which does not require that the
transmission provider create new data. Small Generator
Interconnection Agreements and Procedures, Order No. 792, 145 FERC ]
61,159, at PP 63-64 (2013), clarified, Order No. 792-A, 146 FERC ]
61,214 (2014) (Order No. 792-A).
---------------------------------------------------------------------------

    213. In response to comments on the administrative burden created
by this proposal, we find NextEra's and Portland's comments persuasive.
We therefore modify the proposal to clarify that transmission providers
must provide information regarding costs and in-service completion
times only if such information is ``readily available.'' This will also
address TVA's concerns about increasing the costs of the system impact
study phase. This clarification strikes a balance between providing
more information for the interconnection customer and limiting the
scope of what the transmission provider must do.
    214. In response to EEI's concern about commercially-sensitive
information and CEII, we clarify that the final action does not require
the transmission provider to disclose any such information without
appropriate non-disclosure protections.
    215. In response to comments from AWEA and Generation Developers
requesting that transmission providers provide information regarding
costs and in-service completion times regardless of whether the
interconnection customer requests it, we disagree. We note, consistent
with comments from MidAmerican, that not all interconnection customers
may need access to this information.\368\ The aim of the requirements
adopted here is to improve transparency and better inform
interconnection customer decision-making. Thus, if the interconnection
customer does not request cost or in-service completion date
information, we find it unnecessary to require the transmission
provider to produce this information.
---------------------------------------------------------------------------

    \368\ MidAmerican 2017 Comments at 8.
---------------------------------------------------------------------------

    216. In response to comments from Alevo and Forecasting Coalition
requesting that the transmission provider provide additional
information related to line ratings and underlying symptoms, we find
that such information is outside the scope of the NOPR proposal, which
focuses on contingent facilities.
e. Definition of Contingent Facility
i. Comments
    217. AWEA and Generation Developers support the proposed definition
of contingent facilities.\369\ MISO does not oppose the proposed
definition.\370\ Southern suggests revising the definition to include a
reference to the effect of delayed contingent facilities on an
interconnection request.\371\
---------------------------------------------------------------------------

    \369\ AWEA 2017 Comments at 30; Generation Developers 2017
Comments at 25.
    \370\ MISO 2017 Comments at 24.
    \371\ Southern 2017 Comments at 20.
---------------------------------------------------------------------------

ii. Commission Determination
    218. We adopt the proposed definition in the NOPR for contingent
facilities, with a minor modification to reflect Southern's comments.
Specifically, we adopt the following definition of contingent
facilities (with clarifying additions to the language originally
proposed in the NOPR in italics):

    Contingent Facilities shall mean those unbuilt interconnection
facilities and network upgrades upon which the interconnection
request's costs, timing, and study findings are dependent, and if
delayed or not built, could cause a need for restudies of the
interconnection request or a reassessment of the interconnection
facilities and/or network upgrades and/or costs and timing.

f. Harmonization
i. Comments
    219. Most responsive commenters oppose harmonization.\372\ AWEA
supports a harmonized requirement but explains that it is more critical
that each transmission provider detail the method it will use to
determine contingent facilities.\373\ AWEA asserts that, if a three to
five percent distribution factor test increases the availability of
interconnection service, then it is a just and reasonable
standard.\374\ Some commenters support a distribution factor test,
similar to MISO's test.\375\ AFPA states that consistent standards
across regions will reduce discrimination and disputes and supports a
lower bound on the distribution factor where a facility would not be
considered contingent (e.g., if a facility has a distribution factor
below three percent, it will not be considered contingent).\376\
Portland supports the use of a standardized percentage power transfer
distribution factor but comments that this measure is not typically
used for this purpose. Portland opposes a specific percentage
threshold, arguing that such a threshold could potentially be used to
manipulate the interconnection process.\377\
---------------------------------------------------------------------------

    \372\ See, e.g., Bonneville 2017 Comments at 5; Duke 2017
Comments at 10; Modesto 2017 Comments at 22; Non-Profit Utility
Trade Associations 2017 Comments at 12-13; PJM 2017 Comments at 14.
    \373\ AWEA 2017 Comments at 32.
    \374\ Id. at 34-35.
    \375\ ITC 2017 Comments at 17; AFPA 2017 Comments at 10; AWEA
2017 Comments at 33; Generation Developers 2017 Comments at 26;
Portland 2017 Comments at 3.
    \376\ AFPA 2017 Comments at 10.
    \377\ Portland 2017 Comments at 3.
---------------------------------------------------------------------------

ii. Commission Determination
    220. Based on the comments submitted, it is clear that transmission
providers have different approaches for identifying contingent
facilities. We find that the present record does not support the use of
a distribution factor test or another standard method for identifying
contingent facilities across all regions because it is not clear a
single method would apply across different queue types and footprints.
Therefore, we find that harmonization is not appropriate at this time.
2. Transparency Regarding Study Models and Assumptions
a. NOPR Proposal
    221. To increase transparency and ensure consistency in the
analysis of interconnection requests, the Commission proposed a
requirement that transmission providers detail all the network models
and underlying assumptions used for interconnection studies in their
pro forma LGIPs and on OASIS.\378\ The Commission also proposed to
require that transmission providers include a non-confidential network
model supporting data on OASIS, including, but not limited to, shift
factors, dispatch assumptions, load power factors, and power
flows.\379\ To implement this, the Commission proposed to modify
section 2.3 of the pro forma LGIP as follows (with proposed additions
in italics):
---------------------------------------------------------------------------

    \378\ NOPR, FERC Stats. & Regs. ] 32,719 at P 118.
    \379\ Id. P 119.

    Base Case Data. Transmission Provider shall provide base power
flow, short circuit and stability databases, including all
underlying assumptions, and contingency list upon request subject to
confidentiality provisions in LGIP Section 13.1. Additionally,
Transmission Provider will maintain network models and underlying
assumptions on its OASIS site for access by OASIS users.
Transmission Provider is permitted to require that Interconnection
Customer and OASIS site users sign a confidentiality agreement
before the release of commercially sensitive information or Critical
Energy Infrastructure Information in the Base Case data. Such
databases and lists, hereinafter referred to as Base Cases, shall
include all (1) generation projects and (ii) transmission projects,
including merchant transmission projects that are proposed for the
Transmission System for which a transmission expansion plan has been
---------------------------------------------------------------------------
submitted and approved by the applicable authority.

    222. The Commission sought comment on whether transmission
providers should post other specific network model details and
underlying assumptions on OASIS and should describe in the pro forma
LGIP.\380\ The Commission also sought comment on whether and how
transmission providers should provide notice of any variation from
posted network model assumptions for a specific study, including
whether the Commission should require notice of any variation to be
submitted to the Commission.\381\ In addition, the Commission sought
comment on any confidentiality or security concerns regarding the
posting of specific model assumptions on OASIS or describing them in
the pro forma LGIP.\382\ While the Commission recognized transmission
providers' confidentiality and data security concerns, the Commission
stated that there are likely safeguards that can satisfactorily address
these concerns. The Commission also requested that commenters specify
any data elements that should be subject to confidentiality or non-
disclosure agreements.
---------------------------------------------------------------------------

    \380\ Id. P 120.
    \381\ Id.
    \382\ Id. P 121.
---------------------------------------------------------------------------

b. General
i. Comments
    223. Numerous commenters express support for the proposal to
require transmission providers to list all the network models and
underlying assumptions used for interconnection studies.\383\ Joint
Renewable Parties, AFPA, and IECA believe that the proposal decreases
opportunities for discrimination.\384\ AFPA also states that the
proposal will provide important information and analytical tools for
interconnection customers to identify potential risks and benefits of
project technologies, size, timing, and interconnection points.\385\
EDP states that information access improves the interconnection process
and that an interconnection customer should not have to make major
decisions without understanding how the transmission provider will
evaluate its interconnection request.\386\ EDP notes that tariffs and
business practice manuals often do not contain evaluation and
information production practices utilized by transmission
providers.\387\
---------------------------------------------------------------------------

    \383\ Alevo 2017 Comments at 6; Alliant 2017 Comments at 11;
AFPA 2017 Comments at 11; AWEA 2017 Comments 36-37; CAISO 2017
Comments at 17; Joint Renewable Parties 2017 Comments at 10;
Generation Developers 2017 Comments at 27; EDP 2017 Comments at 6;
Forecasting Coalition 2017 Comments at 4; IECA 2017 Comments at 2;
ITC 2017 Comments at 17; MidAmerican 2017 Comments at 13-14; NEPOOL
2017 Comments at 10; NextEra 2017 Comments at 22; SEIA 2017 Comments
at 18; TDU Systems 2017 Comments at 18; Xcel 2017 Comment at 13-14.
    \384\ Joint Renewable Parties 2017 Comments at 11; AFPA 2017
Comments at 11; IECA 2017 Comments at 2.
    \385\ AFPA 2017 Comments at 11.
    \386\ EDP 2017 Comments at 6.
    \387\ Id.
---------------------------------------------------------------------------

    224. MidAmerican asserts that the proposed reforms would assist
customers in helping to verify the accuracy of required interconnection
facilities and network upgrades.\388\ NextEra also notes that receiving
the models could help to verify study results with unexpectedly high
upgrade costs. NextEra argues that better information about models will
lead to a greater ability to determine whether a site is appropriate
for interconnection and thus will help reduce the number of ``less
favorable'' interconnection requests.\389\ SEIA states that providing
the interconnection customer directly with data will significantly
reduce the

need for study discussion and could eliminate several disputes.\390\
---------------------------------------------------------------------------

    \388\ MidAmerican 2017 Comments at 13-14.
    \389\ NextEra 2017 Comments at 22.
    \390\ SEIA 2017 Comments at 18.
---------------------------------------------------------------------------

    225. Xcel supports adding a description of the network model and
assumptions in the pro forma attachments of the feasibility study
agreement and the system impact study agreement. Xcel states that, if
network model descriptions and assumptions and the study agreements are
posted publicly, then interested interconnection customers can review
those agreements to find how similarly situated generators were
previously studied.\391\
---------------------------------------------------------------------------

    \391\ Xcel 2017 Comment at 13-14.
---------------------------------------------------------------------------

    226. Many commenters voice concerns regarding the proposed
requirement that transmission providers post this information on
OASIS.\392\ CAISO and NYISO state that they already provide network
model and study assumptions on their respective websites.\393\
---------------------------------------------------------------------------

    \392\ CAISO 2017 Comments at 17; NYISO 2017 Comments at 22; TDU
Systems 2017 Comments at 18-19; Xcel 2017 Comment at 14; Duke 2017
Comments at 11-12; EEI 2017 Comments at 40; NEPOOL 2017 Comments at
10; Non-Profit Utility Trade Associations 2017 Comments at 14-15;
OATI 2017 Comments at 4; Salt River 2017 Comments at 12; Southern
2017 Comments at 20; TVA 2017 Comments at 9.
    \393\ CAISO 2017 Comments at 17; NYISO 2017 Comments at 22.
---------------------------------------------------------------------------

    227. NYISO notes that, rather than posting such data on the non-
password protected portion of NYISO's OASIS, NYISO posts
interconnection studies to the password-protected portion of its
website because the studies contain CEII.\394\
---------------------------------------------------------------------------

    \394\ Id.
---------------------------------------------------------------------------

    228. MISO states that it posts its network models for all MISO
market participants, members, and interconnection customers that have
signed non-disclosure agreements. MISO requests clarification that, if
the Commission adopts its proposal, it will not require OASIS posting
if this information is available elsewhere.\395\
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    \395\ MISO 2017 Comments at 27.
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    229. EEI argues that transmission providers should have discretion
as to where to post this information and that interconnection customers
can already request certain information covered by this proposal under
existing CEII processes; it asserts that other information, such as
dispatch information, how transmission providers build their models,
and how contingency files are developed, may include proprietary,
confidential, and commercially sensitive information or intellectual
property.\396\
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    \396\ EEI 2017 Comments at 40-41.
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    230. TDU Systems state that the Commission's pro forma CEII non-
disclosure agreement would be appropriate and sufficient to protect
against disclosure of CEII.\397\ Duke suggests that transmission
providers' power flow models that have been filed with the Commission
and identified as CEII be obtained through the Commission's CEII
processes.\398\
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    \397\ TDU Systems 2017 Comments at 18-19.
    \398\ Duke 2017 Comments at 12.
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    231. Several commenters oppose the proposal and argue that current
posting procedures are sufficient.\399\ For example, Duke suggests that
interconnection customers request a study review to discuss the
underlying study assumptions with the transmission provider.\400\ In
addition, ISO-NE states that its website provides base cases and study
assumptions, subject to CEII protections.\401\ MISO TOs state that, to
the extent that additional information is necessary, the best way to
accomplish this is through improved communications between the
transmission provider, the transmission owner, and the interconnection
customer.\402\ PG&E states that, although an interconnection customer
may need to execute a non-disclosure agreement prior to obtaining this
information, it is already generally available to them.\403\
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    \399\ AES 2017 Comments at 8-9; Duke 2017 Comments at 11; ISO-NE
2017 Comments at 26; MISO TOs 2017 Comments at 27; PG&E 2017
Comments at 5; PJM 2017 Comments at 14; Southern 2017 Comments at
20; TVA 2017 Comments at 9.
    \400\ Duke 2017 Comments at11.
    \401\ ISO-NE 2017 Comments at 26.
    \402\ MISO TOs 2017 Comments at 27-28.
    \403\ PG&E 2017 Comments at 6.
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    232. Commenters that oppose the proposal argue that it may be
administratively burdensome.\404\ Duke argues, moreover, that the
Commission should instead require transmission providers to review the
information they already post on OASIS that provides a summary of the
transmission planning processes. Then, if necessary, the Commission
could augment that description with a high-level description of how
transmission providers conduct interconnection studies.\405\ Similarly,
EEI requests that the Commission only require transmission providers to
furnish high-level descriptions on model development.\406\ EEI also
argues that transmission providers should only have to post updates if
there are material changes in the generally applied assumptions.\407\
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    \404\ Duke 2017 Comments at 11; EEI 2017 Comments at 40;
NorthWestern 2017 Comments at 4-6; NYISO 2017 Comments at 23; PG&E
2017 Comments at 5; Salt River 2017 Comments at 12; Tri-State 2017
Comments at 6-7.
    \405\ Duke 2017 Comments at 11.
    \406\ EEI 2017 Comments at 40.
    \407\ Id. at 43.
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    233. NorthWestern expresses concern that the proposal would be
unnecessary and cumbersome given base case changes and asserts that a
complete list of models would not benefit an interconnection
customer.\408\ Further, NorthWestern states that requiring a non-
disclosure agreement from each potential interconnection customer prior
to the feasibility study would administratively burden transmission
providers. It also argues that, in the West, interconnection customers
seeking additional information about study benefits and assumptions
currently have the ability to request model details from the Western
Electricity Coordinating Council.\409\
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    \408\ NorthWestern 2017 Comments at 5.
    \409\ Id. at 6.
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    234. NYISO opposes the provision of shift factors, which, it
argues, only pertain to power flow and thermal analyses, which are more
applicable to interconnections in RTOs/ISOs that offer physical
transmission rights.\410\ Tri-State argues that large-scale system
planning is dynamic and often requires changes to in-service dates,
identification of new delivery points, project cancellations,
generation assumptions, and assumed demand levels.\411\
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    \410\ NYISO 2017 Comments at 23.
    \411\ Tri-State 2017 Comments at 6.
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    235. Xcel notes that, because each interconnection request is
unique, the specific network model assumptions used are also usually
distinctive. Xcel argues that the Commission should grant transmission
providers flexibility to provide the detailed, unique specifics of the
network models in individual study agreements.\412\ Xcel also proposes
that interconnection customers review the general process, as described
in the LGIP or a business practice manual, as well as published study
agreements to gain insights into expectations for modeling. Xcel states
that the customer can discuss the specific modeling process and
assumptions for its request with the transmission provider, and the
agreement to be modeled would be memorialized in the agreements posted
on OASIS. Xcel asserts that this process would provide significant
transparency while allowing the use of the most appropriate studies and
up-to-date assumptions for interconnection requests.\413\
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    \412\ Xcel 2017 Comments at 13.
    \413\ Id. at 14.

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ii. Commission Determination
    236. We adopt the NOPR proposal, with modifications. Specifically,
this final action revises section 2.3 of the pro forma LGIP to read as
follows (the bracketed text reflects deletions from, and the italicized
text reflects additions to, the language proposed in the NOPR):

    Base Case Data. Transmission Provider shall maintain [provide]
base power flow, short circuit and stability databases, including
all underlying assumptions, and contingency list on either its OASIS
site or a password-protected website, [upon request] subject to
confidentiality provisions in LGIP Section 13.1. [Additionally]In
addition, Transmission Provider shall [will] maintain network models
and underlying assumptions on either its OASIS site or a password-
protected website [for access by OASIS users]. Such network models
and underlying assumptions should reasonably represent those used
during the most recent interconnection study and be representative
of current system conditions. If Transmission Provider posts this
information on a password-protected website, a link to the
information must be provided on Transmission Provider's OASIS site.
Transmission Provider is permitted to require that Interconnection
Customers [and], OASIS site users, and password-protected website
users sign a confidentiality agreement before the release of
commercially sensitive information or Critical Energy Infrastructure
Information in the Base Case data. Such databases and lists,
hereinafter referred to as Base Cases, shall include all (1)
generation projects and (2 [ii]) [414] transmission
projects, including merchant transmission projects that are proposed
for the Transmission System for which a transmission expansion plan
has been submitted and approved by the applicable authority.
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    \414\ In this final action, we correct a typographical error in
the pro forma LGIP.

    237. Most responsive commenters note that the proposal could
significantly increase transparency in the study process. We disagree
with commenters that argue that current posting procedures are
sufficient. The record before us demonstrates that transmission
providers do not consistently make their network models and assumptions
available, and access to information regarding the assumptions used is
often inconsistent across regions.\415\ We believe the revisions to
section 2.3 of the pro forma LGIP will reduce the possibility that some
interconnection customers will have unduly discriminatory access to
relevant information and will generally increase transparency for
interconnection customers by requiring that network models and
assumptions used by transmission providers be made available, subject
to the appropriate confidentiality and information requirements. We
expect that these revisions will allow interconnection customers to
make more informed interconnection decisions while also holding
transmission providers accountable as to which network models and
assumptions they use to assess interconnection requests.
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    \415\ NOPR, FERC Stats. & Regs. ] 32,719 at PP 111-112; see also
NextEra 2017 Comments at 22; Alliant 2017 Comments at 11.
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    238. However, we find persuasive concerns voiced by several
commenters regarding the proposal's requirement to post the network
model and assumption information on OASIS. Specifically, we recognize
that a requirement to move information onto OASIS could burden
transmission providers that currently make this information available
to interconnection customers elsewhere. Therefore, we believe a
transmission provider should be able to decide to maintain the required
information on its website as long as it has a link to the location of
the information on OASIS, as OASIS is the central location for all the
information needed to request interconnection service. Accordingly, the
revisions to section 2.3 of the pro forma LGIP require transmission
providers to post network models and assumptions, subject to the
appropriate confidentiality and information requirements, on OASIS and/
or on a password-protected website. These revisions strike an
appropriate balance by increasing transparency while also limiting the
burden on transmission providers.
    239. In response to those arguments alleging that maintaining
network models and underlying assumptions on OASIS or a password-
protected website may be administratively burdensome, we find the
benefits of increased transparency resulting from the revisions to
section 2.3 of the pro forma LGIP will outweigh the burden placed on
transmission providers to post and maintain up-to-date network models
and underlying assumptions. Instead, we note that increasing
transparency of network models and assumptions will allow
interconnection customers to make informed interconnection decisions,
which could potentially help interconnection customers avoid entering
the queue with non-viable interconnection requests. Informed
interconnection decisions will also allow transmission providers to
improve queue management. Improved queue management, in turn, should
aid in decreasing the administrative burden on transmission providers.
In addition, increased transparency will also mitigate the potential
for study disputes, re-studies and late-stage withdrawals, thus
increasing the efficiency of the interconnection process.
    240. In response to confidentiality and data security concerns
associated with providing certain information and system access, we
reaffirm that there are safeguards that can be put in place to
satisfactorily address these concerns. With the revisions in this final
action, section 2.3 of the pro forma LGIP allows the transmission
provider to require that the interconnection customer sign a
confidentiality agreement before the release of commercially sensitive
information. We agree with commenters that transmission providers
should only provide commercially-sensitive information, such as
contingency files and specific dispatch information, under a non-
disclosure agreement. We note that the information that this final
action requires transmission providers to post will be available on a
password-protected website or on the transmission provider's OASIS
site.
    241. With regard to CEII, we note that the Commission's CEII
regulations in 18 CFR 388.113 only govern ``the procedures for
submitting, designating, handling, sharing, and disseminating [CEII]
submitted to or generated by the Commission.'' \416\ However, to the
extent that certain information that is currently designated by the
Commission as CEII is implicated by this portion of the final action,
this final action makes no changes to that information's CEII
designation or to the Commission's existing CEII requirements.
Additionally, even if the information has been designated as CEII,
Sec.  388.113 of the Commission's regulations does not govern the
transmission provider's handling, sharing, and disseminating of
information that the transmission provider submitted for CEII
designation, including how it disseminates that information on its
OASIS site or password-protected website. We note, however, that
nothing in Sec.  388.113 of the Commission's regulations precludes a
transmission provider from taking necessary steps to protect
information within its custody or control to ensure the safety and
security of the electric grid. Specifically, we note that pro forma
LGIP section 2.3 permits transmission providers to require a
confidentiality agreement for anyone that wishes to access
``commercially sensitive information or [information that has been
designated as CEII]'' that may be posted in the base case data on the
transmission provider's OASIS site or password-protected website.
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    \416\ 18 CFR 388.113 (2017) (emphasis added).
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    242. Upon consideration of the comments, we withdraw the NOPR

proposal to require transmission providers to post information
``including, but not limited to, shift factors, dispatch assumptions,
load power factors, and power flows.'' \417\ Such a requirement could
result in transmission providers posting certain information that is
not informative to interconnection customers and which could delay or
otherwise burden the interconnection study process. For example, NYISO
states that shift factors generally only pertain to power flow and
thermal analyses, which are more applicable to interconnections in
RTOs/ISOs that offer physical transmission rights.\418\
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    \417\ NOPR, FERC Stats. & Regs. ] 32,719 at P 119.
    \418\ NYISO 2017 Comments at 23.
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c. Suggested Modifications to Transparency Regarding Study Models and
Assumptions Proposal
i. Comments
    243. Multiple commenters support the proposal but offer suggestions
to increase transparency.\419\ For example, AWEA suggests that
transmission providers should have to review interconnection study
models and assumptions every two years and submit a filing pursuant to
section 205 of the FPA justifying the model and assumptions to ensure
that study models and assumptions are non-discriminatory, realistic,
appropriate for generation or regional characteristics, and
accountable.\420\
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    \419\ AWEA 2017 Comments at 37; Generation Developers 2017
Comments at 28; NEPOOL 2017 Comments at 10; NextEra 2017 Comments at
22; TDU Systems 2017 Comments at 18; Xcel 2017 Comments at 13.
    \420\ AWEA 2017 Comments at 37; see also Generation Developers
2017 Comments at 31.
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