[Federal Register Volume 84, Number 60 (Thursday, March 28, 2019)]
[Notices]
[Pages 11759-11768]
[FR Doc No: 2019-05895]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Docket No. PL19-3-000]

Inquiry Regarding the Commission's Electric Transmission
Incentives Policy

AGENCY: Federal Energy Regulatory Commission.

ACTION: Notice of inquiry.

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SUMMARY: In this Notice of Inquiry, the Federal Energy Regulatory
Commission (Commission) seeks comments on the scope and implementation
of its electric transmission incentives regulations and policy.

DATES: Initial Comments are due June 25, 2019, and Reply Comments are
due July 25, 2019.

ADDRESSES: Comments, identified by docket number, may be filed
electronically at http://www.ferc.gov in acceptable native applications
and print-to-PDF, but not in scanned or picture format. For those
unable to file electronically, comments may be filed by mail or hand-
delivery to: Federal Energy Regulatory Commission, Secretary of the
Commission, 888 First Street NE, Washington, DC 20426. The Comment
Procedures section of this document contains more detailed filing
procedures.

FOR FURTHER INFORMATION CONTACT:
David Tobenkin (Technical Information), Office of Energy Policy and
Innovation, Federal Energy Regulatory Commission, 888 First Street NE,
Washington, DC 20426,<PHONE_NUMBER><EMAIL_ADDRESS>Adam Batenhorst (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street NE, Washington,
DC 20426,<PHONE_NUMBER><EMAIL_ADDRESS>Adam Pollock (Technical Information), Office of Energy Market
Regulation, Federal Energy Regulatory Commission, 888 First Street NE,
Washington, DC 20426,<PHONE_NUMBER><EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION:

Table of Contents

                                                          Paragraph Nos.

I. Background...........................................               3
    A. FPA Section 219..................................               3
    B. Order Nos. 679 and 679-A.........................               6
    C. 2012 Policy Statement............................               9
    D. Order No. 1000...................................              11
II. Subject of the Notice of Inquiry....................              13
    A. Approach to Incentive Policy.....................              14
        1. Incentives Based on Project Risks and                      15
         Challenges.....................................
        2. Incentives Based on Expected Project Benefits              16
        3. Incentives Based on Project Characteristics..              18
    B. Incentive Objectives.............................              19
        1. Reliability Benefits.........................              22
        2. Economic Efficiency Benefits.................              24
        3. Persistent Geographic Needs..................              25
        4. Flexible Transmission System Operation.......              26
        5. Security.....................................              27
        6. Resilience...................................              28
        7. Improving Existing Transmission Facilities...              29
        8. Interregional Transmission Projects..........              30
        9. Unlocking Locationally Constrained Resources.              31
        10. Ownership by Non-Public Utilities...........              32
        11. Order No. 1000 Transmission Projects........              33
        12. Transmission Projects in Non-RTO/ISO Regions              35
    C. Existing Incentives..............................              36
        1. ROE-Adder Incentives.........................              37
        2. Non-ROE Transmission Incentives..............              40
    D. Mechanics and Implementation.....................              44
        1. Duration of Incentives.......................              44
        2. Case-by-Case vs. Automatic Approach in                     45
         Reviewing Incentive Applications...............
        3. Interaction Between Different Potential                    46
         Incentives in Determining Correct Level of ROE
         Incentives.....................................
        4. Bounds on ROE Incentives.....................              47
    E. Metrics for Evaluating the Effectiveness of                    48
     Incentives.........................................
III. Comment Procedures.................................              49
IV. Document Availability...............................              53

    1. In this Notice of Inquiry, the Commission seeks comment on the
scope and implementation of its electric transmission incentives
regulations and policy pursuant to section 1241 of the Energy Policy
Act of 2005 (EPAct 2005),\1\ codified as section 219 of the Federal
Power Act (FPA),\2\ which directed the Commission to use transmission
incentives to help ensure reliability and reduce the cost of delivered
power by reducing transmission congestion.\3\ In 2006, the

Commission implemented section 1241 by issuing Order No. 679,\4\ which
established the Commission's basic approach to transmission incentives
and enumerated a series of potential incentives that the Commission
would consider. The Commission subsequently refined its approach to
transmission incentives in a 2012 policy statement (2012 Incentives
Policy Statement), which provided guidance on the Commission's
interpretation of Order No. 679 and its approach toward granting
transmission incentives, but did not alter the Commission's regulations
or Order No. 679's basic approach to granting transmission incentives.
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    \1\ Energy Policy Act of 2005, Public Law 109-58, sec. 1261 et
seq., 119 Stat. 594 (2005).
    \2\ 16 U.S.C. 824s.
    \3\ The Commission is generally reevaluating its ROE policy in a
separate Notice of Inquiry issued concurrently with this notice.
Inquiry Regarding the Commission's Policy for Determining Return on
Equity, 166 FERC ] 61,207 (2019). Below, see infra II.D.3, the
Commission seeks comments regarding any interactions between the
subject matters of these proceedings.
    \4\ Promoting Transmission Investment through Pricing Reform,
Order No. 679, 116 FERC ] 61,057, order on reh'g, Order No. 679-A,
117 FERC ] 61,345 (2006), order on reh'g, 119 FERC ] 61,062 (2007).
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    2. It has been nearly 13 years since the Commission promulgated
Order No. 679 and nearly seven years since the Commission issued a
policy statement to provide additional guidance regarding its
evaluation of applications for transmission incentives under FPA
section 219.\5\ In that time, there have been a number of significant
developments in how transmission is planned, developed, operated, and
maintained. In light of those developments and the records compiled in
various incentives proceedings before the Commission, we believe that
it is appropriate to seek comment from stakeholders on the scope and
implementation of the Commission's transmission incentives policy and
on how the Commission should evaluate future \6\ requests for
transmission incentives in a manner consistent with Congress's
direction in section 219. Accordingly, through this Notice of Inquiry,
the Commission solicits comments on variety of issues related to
transmission incentives policy, as discussed in the following sections.
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    \5\ Promoting Transmission Investment Through Pricing Reform,
141 FERC ] 61,129 (2012) (2012 Incentives Policy Statement).
    \6\ During the pendency of this proceeding, the Commission will
continue to evaluate incentive requests under Order No. 679, as
informed by the 2012 Incentives Policy Statement, on a case-by-case
basis.
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I. Background

A. FPA Section 219

    3. Prior to 2005, the Commission considered requests for certain
transmission incentives pursuant to FPA section 205.\7\ In 2005,
Congress amended the FPA to, as relevant here, add a new section
219.\8\ Section 219(a) ``directed FERC to promulgate a rule providing
incentive-based rates for electric transmission for the purpose of
benefitting consumers through increased reliability and lower costs of
power.'' \9\ Section 219(b) included a number of specific directives in
the required rulemaking, including that the Commission should:
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    \7\ 16 U.S.C. 824d; see also Maine Public Utilities Commission
v. FERC, 454 F.3d 278, 288 (D.C. Cir. 2006).
    \8\ Energy Policy Act of 2005, Public Law 109-58, sec. 1241.
    \9\ California Pub. Utilities Comm'n v. FERC, 879 F.3d 966, 970
(9th Cir. 2018).
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     Promote reliable and economically efficient transmission
and generation of electricity by promoting capital investment in the
enlargement, improvement, maintenance, and operation of all facilities
for the transmission of electric energy in interstate commerce,
regardless of the ownership of the facilities; \10\
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    \10\ 16 U.S.C. 824s(b)(1).
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     provide a return on equity that attracts new investment in
transmission facilities, including related transmission technologies;
\11\
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    \11\ Id. 824s(b)(2).
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     encourage deployment of transmission technologies and
other measures to increase the capacity and efficiency of existing
transmission facilities and improve the operation of the facilities;
\12\ and
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    \12\ Id. 824s(b)(3).
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     allow the recovery of all prudently incurred costs
necessary to comply with mandatory reliability standards issued
pursuant to section 215 of the FPA,\13\ and all prudently incurred
costs related to transmission infrastructure development pursuant to
section 216 of the FPA.\14\
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    \13\ FPA section 215 addresses the Commission's role in ensuring
electric reliability of the bulk power system. Id. 824o.
    \14\ Id. 824s(b)(4). FPA section 216 addresses designation of
and siting of transmission facilities within National Interest
Electric Transmission Corridors. Id. 824p.
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    4. Section 219(c) requires that the Commission shall, to the extent
within its jurisdiction, provide for incentives to each transmitting
utility or electric utility that joins a Transmission Organization \15\
and ensure that any costs recoverable pursuant to this subsection may
be recovered by such utility through the transmission rates charged by
such utility or through the transmission rates charged by the
Transmission Organization that provides transmission service to such
utility.
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    \15\ The Commission defines a Transmission Organization as a
Regional Transmission Organization, Independent System Operator,
independent transmission provider, or other transmission
organization finally approved by the Commission for the operation of
transmission facilities. 18 CFR 35.35(b)(2).
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    5. Finally, section 219(d) provides that all rates approved
pursuant to a rulemaking adopted pursuant to section 219 are subject to
the requirement in FPA sections 205 and 206 that all rates, charges,
terms, and conditions be just and reasonable and not unduly
discriminatory or preferential.

B. Order Nos. 679 and 679-A

    6. On July 20, 2006, the Commission issued Order No. 679,
fulfilling the rulemaking requirement in section 219(a). The Commission
explained that, to receive an incentive, an applicant must satisfy the
statutory threshold set forth in section 219(a) by demonstrating that
the transmission facilities for which it seeks incentives either ensure
reliability or reduce the cost of delivered power by reducing
transmission congestion. If the applicant satisfies that threshold, it
must then demonstrate that there is a nexus between the incentive
sought and the investment being made. The Commission stated that the
section 219(a) threshold and the nexus test were to be applied on a
case-by-case basis.\16\ In its discussion of the nexus test, the
Commission explained that the ``most compelling'' candidates for
incentives are ``new projects that present special risks or challenges,
not routine investments made in the ordinary course of expanding the
system to provide safe and reliable transmission service.'' \17\
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    \16\ Order No. 679, 116 FERC ] 61,057 at PP 22, 24.
    \17\ Id. PP 23, 60.
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    7. The Commission also described a variety of incentives that would
potentially be available, including:
     Adders to a base ROE: (1) To compensate for the risks and
challenges of a specific transmission project (ROE adder for risks and
challenges); (2) for forming a transmission-only company (Transco
adder); (3) for joining a regional transmission organization (RTO) or
independent system operator (ISO) (RTO/ISO adder); or (4) for use of an
advanced transmission technology (technology adder);
     recovery of 100 percent of prudently incurred costs of
transmission facilities that are cancelled or abandoned due to factors
that are beyond the control of the public utility (abandoned plant
incentive);
     inclusion of 100 percent of construction work in progress
(CWIP) in rate base (CWIP incentive);

     hypothetical capital structures;
     accelerated depreciation for rate recovery; and
     recovery of prudently incurred pre-commercial operations
costs as an expense or through a regulatory asset (regulatory asset
incentive).
    8. On December 22, 2006, in Order No. 679-A, the Commission granted
rehearing in part and denied rehearing in part of Order No. 679.\18\
The Commission largely affirmed the conclusions discussed in the
previous paragraphs while refining certain other aspects of Order No.
679.
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    \18\ Order No. 679-A, 117 FERC ] 61,345.
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C. 2012 Policy Statement

    9. On November 15, 2012, the Commission issued a policy statement
to provide additional guidance regarding its evaluation of applications
for transmission incentives under section 219. In particular, the
Commission reframed the nexus test for applicants seeking the ROE adder
for risks and challenges and eliminated the technology ROE adder.\19\
The Commission stated that it would expect an applicant seeking an ROE
adder for risks and challenges to demonstrate that: (1) The proposed
transmission project faces risks and challenges that were not either
already accounted for in the applicant's base ROE or addressed through
risk-reducing incentives; (2) it is taking appropriate steps and using
appropriate mechanisms to minimize its risk during transmission project
development; (3) alternatives to the transmission project had been, or
would be, considered in either a relevant transmission planning process
or another appropriate forum; and (4) it commits to limiting the
application of the ROE incentive to a cost estimate.\20\
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    \19\ The Commission stated that, with respect to possible ROE
incentives, it would prospectively consider advanced technologies
only as part of an application for an ROE adder for risks and
challenges. 2012 Incentives Policy Statement, 141 FERC ] 61,129 at P
23.
    \20\ Id. PP 20-28.
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    10. The Commission provided several examples of categories of
transmission projects that might satisfy the above-noted ``risks and
challenges'' expectation, including transmission projects that would:
(1) Relieve chronic or severe grid congestion that has had demonstrated
cost impacts to consumers; (2) unlock location-constrained generation
resources that previously had limited or no access to the wholesale
electricity markets; or (3) apply new technologies to facilitate more
efficient and reliable usage and operation of existing or new
facilities.\21\
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    \21\ Id. P 21. The Commission noted these examples of types of
transmission projects that might qualify for an ROE adder for risks
and challenges was not an exhaustive list. Id. P 22.
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D. Order No. 1000

    11. In 2011, the Commission issued Order No. 1000, which instituted
certain transmission planning and cost allocation reforms for public
utility transmission providers.\22\ Notably, Order No. 1000 requires:
(1) That each public utility transmission provider participate in a
regional transmission planning process that produces a regional
transmission plan; (2) that each public utility transmission provider
amend its open access transmission tariff to describe procedures that
provide for the consideration of transmission needs driven by public
policy requirements in the local and regional transmission planning
processes; (3) the elimination from Commission-approved tariffs and
agreements a federal right of first refusal for certain new
transmission facilities; and (4) coordination among neighboring
transmission planning regions to identify potential interregional
transmission facilities.\23\
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    \22\ Transmission Planning and Cost Allocation by Transmission
Owning and Operating Public Utilities, Order No. 1000, 136 FERC ]
61,051 (2011), order on reh'g, Order No. 1000-A, 139 FERC ] 61,132,
order on reh'g and clarification, Order No. 1000-B, 141 FERC ]
61,044 (2012), aff'd sub nom. S.C. Pub. Serv. Auth. v. FERC, 762
F.3d 41 (D.C. Cir. 2014).
    \23\ See Order No. 1000, 136 FERC ] 61,051 at PP 4-6, 8.
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    12. The various regional transmission planning processes
implemented in response to Order No. 1000 became effective between 2013
and 2015, after the Commission issued the 2012 Incentives Policy
Statement. The transmission planning regions have all now conducted at
least one iteration of their regional transmission planning process,
with some having conducted as many as three. Although Order No. 1000
does not directly address the Commission's obligations under section
219, the aforementioned reforms had significant implications for how
transmission facilities are planned and developed.

II. Subject of the Notice of Inquiry

    13. As part of ensuring that the Commission continues to meet our
statutory obligations, the Commission, on occasion, engages in public
inquiry to gauge whether there is a need to add to, modify, or
eliminate certain policies or regulatory requirements. It has now been
nearly 13 years since the Commission issued Order No. 679. During that
time, the landscape for planning, developing, operating, and
maintaining transmission infrastructure has changed considerably. Those
changes include the Commission's issuance of Order No. 1000, an
evolution in the generation mix and the number of new resources seeking
transmission service, shifts in load patterns, and an increased
emphasis on the reliability of transmission infrastructure. The
Commission is issuing this NOI to obtain information that will assist
us in evaluating our transmission incentives policy and ensuring that
the policy continues to satisfy our obligations under section 219 of
the FPA. The following sections present a series of questions regarding
the Commission's transmission incentives policy. Commenters are
encouraged to respond to these questions in detail and, where
appropriate, provide specific examples to support their comments and
recommendations. Commenters need not answer every question below.

A. Approach to Incentive Policy

    14. The Commission in Order No. 679 established a requirement that
each applicant demonstrate that there is a nexus between the incentive
sought and the risks and challenges of the investment being made.\24\
The Commission is considering whether the ``risks and challenges''
approach remains the most effective means of complying with Congress's
directives in section 219. To that end, the Commission is seeking
comments on how it should approach evaluating requests for incentives,
including upon the current risks and challenges approach as well as
upon other potential approaches, including, but not limited to, the
alternative approaches discussed below. In addressing these approaches,
commenters should consider how each approach could or should be
implemented and the potential benefits and drawbacks of each approach.
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    \24\ See Order No. 679, 116 FERC ] 61,057 at PP 26.
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1. Incentives Based on Project Risks and Challenges
    15. As noted, the Commission in Order No. 679 established a
requirement that each applicant must demonstrate that there is a nexus
between the incentive sought and the risks and challenges of investment
being made. Although the 2012 Incentives Policy Statement reframed this
standard, it remains central to the Commission's approach in evaluating
incentive applications.
    (Q 1) Should the Commission retain the risks and challenges
framework for evaluating incentive applications?

    (Q 2) Is providing incentives to address risks and challenges an
appropriate proxy for the expected benefits brought by transmission and
identified in section 219 (i.e., ensuring reliability or reducing the
cost of delivered power by reducing transmission congestion)? If risks
and challenges are not a useful proxy for benefits, is it an
appropriate approach for other reasons?
    (Q 3) The Commission currently considers risks both in calculating
a public utility's base ROE and in assessing the availability and level
of any ROE adder for risks and challenges. Is this approach still
appropriate? If so, which risks are relevant to each inquiry, and, if
they differ, how should the Commission distinguish between risks and
challenges examined in each inquiry?
2. Incentives Based on Expected Project Benefits
    16. The Commission could instead evaluate incentive requests based
on the transmission project's potential to achieve benefits related to
reliability and reductions in the cost of delivered power by reducing
transmission congestion.\25\
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    \25\ Potential examples of these benefits and their potential
relationship to types of transmission projects are described below
in Section II.B.1-2.
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    (Q 4) Would directly examining a transmission project's expected
benefits improve the Commission's transmission incentives policy,
consistent with the goals of section 219? Are there drawbacks to this
approach, particularly relative to the current risks and challenges
framework?
    (Q 5) If the Commission adopts a benefits approach, should it lay
out general principles and/or bright line criteria for evaluating the
potential benefits of a proposed transmission project? If so, how
should the Commission establish the principles or criteria?
    (Q 6) How would a direct evaluation of expected benefits, instead
of using risks and challenges as a proxy, impact certainty for project
developers?
    (Q 7) Should transmission projects with a demonstrated likelihood
of benefits be awarded incentives automatically? How could the
Commission administer such an approach?
    17. Although section 219 requires the Commission to consider
performance-based ratemaking and to ensure that incentive-based rates
are just and reasonable,\26\ Congress did not require the Commission to
base an incentive award on a specific level of benefits, either on its
own or relative to the costs of the project(s) in question. Order No.
679 considered but rejected such a requirement.\27\ The Commission is
examining whether and how it might consider benefits relative to costs
when evaluating a request for incentives.
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    \26\ 16 U.S.C. 824s(a), (d).
    \27\ Order No. 679, 116 FERC ] 61,057 at P 65. The Commission
notes that the 2012 Incentives Policy Statement directed applicants
to limit ROE adder for risks and challenges to a cost estimate and
demonstrate the use of risk reduction techniques. 2012 Incentives
Policy Statement, 141 FERC ] 61,129 at PP 24, 28-29.
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    (Q 8) If the Commission grants incentives based on expected
benefits, should the level of the incentive vary based on the level of
the expected benefits relative to transmission project costs? If so,
how should the Commission determine how to vary incentives based on the
size of benefits?
    (Q 9) Should incentives be conditioned upon meeting benefit-to-cost
benchmarks, such as a benefit-cost ratio? If so, what benefit-to-cost
ratios should be used?
    (Q 10) Should incentives be based only on benefit-to-cost estimates
or should the Commission condition the incentives on evidence that that
those benefit-to-cost estimates were realized?
    (Q 11) If an incentive is conditioned upon a transmission developer
meeting benefit-to-cost benchmarks, what types of benefits and costs
should a transmission developer include, and the Commission consider to
support requests for such incentives? Should there be measurement and
verification, and if so, over what time period? If expected benefits do
not accrue, should the incentive be revoked?
3. Incentives Based on Project Characteristics
    18. As an alternative to a direct examination of expected benefits,
the Commission could use transmission project characteristics as a
proxy for expected benefits. These project characteristics could
include, for example, transmission projects located in regions with
persistent needs, interregional transmissions projects, or transmission
projects that unlock constrained resources. Such an approach could also
consider granting incentives based upon inclusion of specific
transmission technologies.\28\
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    \28\ Potential examples of these characteristics and their
potential relationship to types of transmission projects are
described below in Section II.B.3-12.
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    (Q 12) How, if at all, would examining transmission projects'
characteristics in evaluations of transmission incentives applications
improve the Commission's transmission incentives policy and achieve the
goals of section 219? Are there drawbacks to this approach,
particularly relative to the current risks and challenges framework?
Would this approach result in different outcomes, as compared to the
current risks and challenges approach for granting incentives?
    (Q 13) If the Commission adopts an approach based on project
characteristics, should it lay out general principles and/or bright
line criteria for identifying or evaluating those characteristics?
    (Q 14) If so, how should applicable criteria be established, and,
in cases where more than one criterion applies, how should they be
evaluated in combination?
    (Q 15) How would an approach based on project characteristics
impact certainty for project developers, particularly relative to the
current risks and challenges framework?
    (Q 16) Should transmission projects with certain characteristics be
awarded incentives automatically? How could the Commission administer
such an approach?

B. Incentive Objectives

    19. Prior to 2005, the Commission considered requests for certain
transmission incentives pursuant to FPA section 205. As noted, section
219 directs the Commission to establish a transmission incentives
policy that benefits consumers by ensuring reliability and reducing the
cost of delivered power by reducing transmission congestion.\29\ In
addition, section 219 directs the Commission to promote certain
specified goals--namely, promoting capital investment in the
enlargement, improvement, maintenance, and operation of jurisdictional
transmission facilities; providing an ROE that attracts investment in
new transmission facilities and technologies; encouraging deployment of
technologies and other measures that enhance the capacity, efficiency,
and operation of existing transmission facilities; incentivizing
transmission-owning public utilities to join an RTO; and allowing
recovery of certain types of prudently incurred costs.\30\
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    \29\ 16 U.S.C. 824s(a).
    \30\ Id. 824s(b)-(c).
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    20. This section seeks comment on what the Commission should
incentivize in order to satisfy Congress's directives in section 219.
In particular, we seek comment on what expected benefits or project
characteristics warrant incentives. In discussing each benefit or
project characteristic that the Commission should be incentivizing,

commenters should consider: (1) How the Commission should define the
benefit or project characteristics in question; (2) whether the
Commission can quantify or measure the benefits or project
characteristics, where applicable, how it should do so; (3) how the
Commission should incentivize the benefit or project characteristics if
it decides to do so; and (4) the legal basis, extent, and nature of the
incentives. For ROE adder incentives, the Commission is interested in
how many basis points would be appropriate for a given incentive. The
Commission is also interested in whether and how incentives other than
ROE adders could encourage facilities with benefits or project
characteristics, including those outlined below.
    21. The sections below enumerate certain benefits or project
characteristics that commenters may wish to address, although
commenters need not limit their comments to these benefits or project
characteristics. Commenters that choose to comment on the benefits and
project characteristics discussed below should consider both the
questions listed in the previous paragraph as well as the specific
questions accompanying the following benefits or project
characteristics.
1. Reliability Benefits
    22. Benefitting customers by ensuring reliability was one of
Congress's core objectives in section 219. Transmission owners are
already required to address many facets of reliability through
compliance with the North American Electric Reliability Corporation
(NERC) reliability standards and various other planning criteria.
Nevertheless, the Commission could potentially tailor incentives to
promote reliability transmission projects that significantly enhance
transmission reliability above and beyond what is required by the NERC
reliability standards or other planning criteria.
    (Q 17) Should the Commission tailor incentives to promote these
types of projects based on their expected reliability benefits? If so,
how should the Commission differentiate these projects from others
required to meet reliability standards?
    (Q 18) Are there specific reliability benefits or project
characteristics that could merit such an approach?
    (Q 19) If the Commission tailored incentives for reliability
benefits, how should the Commission measure the expected enhancement to
transmission reliability? Should there be a threshold or bright line
test applied? If so, how?
    23. One way in which additional transmission facilities may further
encourage reliability is by expanding access to essential reliability
services, which can, among other things, allow delivery of sufficient
resources to support and stabilize grid frequency during disturbances
and ensure adequate voltage control and reactive power capability.
    (Q 20) Should the Commission incentivize transmission facilities
that expand access to essential reliability services, such as frequency
support, ramping capability, and voltage support?
    (Q 21) If so, how should the Commission assess and measure whether
transmission projects expand access to essential reliability services?
2. Economic Efficiency Benefits
    24. Transmission projects can promote economic efficiency by
reducing congestion, which allows efficient dispatch of resources,
facilitating the interconnection of additional generation, and
facilitating the transmission of additional generation to load
centers.\31\ The Commission could tailor incentives to promote
transmission projects that accomplish either of these two outcomes.
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    \31\ See Order No. 679, 116 FERC ] 61,057 at P 25; see also 2012
Incentives Policy Statement, 141 FERC ] 61,129 at P 21.
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    (Q 22) Should the Commission tailor incentives to promote projects
that accomplish the outcomes of reducing congestion or facilitating
access to additional generation?
    (Q 23) Should the Commission establish bright line metrics, such as
a specified level of reduction in average production costs, to
determine whether a transmission project merits incentives?
    (Q 24) Should the Commission consider incentivizing transmission
projects that are scaled to more efficiently facilitate interconnection
of, or transmission to, additional generation? What other measurable
economic efficiency benefits should be considered a bright line metric
for the purposes of economic efficiency?
    (Q 25) How should the applicable bright line criteria be
established, and, in cases where more than one criterion applies, how
should they be evaluated in combination?
3. Persistent Geographic Needs
    25. Section 219's objective of promoting the development of
transmission facilities that ensure reliability and/or reduce
congestion may be particularly important in regions of the country that
have experienced chronic, long-term congestion or require operating
procedures in place to address long-term reliability issues.
    (Q 26) Should the Commission utilize an incentives approach that is
based on targeting certain geographic areas where transmission projects
would enhance reliability and/or have particular economic efficiency
benefits? If so, how should the relevant geographic areas be identified
and defined? What entity (e.g., the Commission, RTOs/ISOs, state
regulators, other stakeholders) should designate such areas?
    (Q 27) What criteria should be used to define such geographic
areas? Procedurally, how should such geographic areas be determined,
monitored, and updated?
    (Q 28) Should the relevant geographic areas be defined on an ex
ante basis and/or should the transmission developer have the burden of
demonstrating that the relevant transmission project falls within a
geographic region that has an acute need for transmission?
4. Flexible Transmission System Operation
    26. As the generation mix changes and load patterns evolve, the
requirements of the transmission system will also change. Flexibility
characteristics of the transmission system, such as increased line
rating precision, greater power flow control, and technologies,
including energy storage,\32\ may be able to facilitate the
transmission system's ability to respond to changing circumstances.
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    \32\ See W. Grid Dev., LLC, 130 FERC ] 61,056, at PP 2, 43-46,
order denying reh'g, 133 FERC ] 61,029 (2010).
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    (Q 29) How can flexibility characteristics improve the operation of
the transmission system?
    (Q 30) Should the Commission incentivize flexibility
characteristics and, if so, how should it do so?
    (Q 31) How could the Commission define ``flexibility'' in this
context?
5. Security
    27. Enhancing the physical and cyber-security of existing
jurisdictional transmission facilities, including new facilities, can
improve the facilities' ability to contribute to the reliability of the
bulk power system. Addressing the security of the transmission system
is a priority of the Commission.\33\
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    \33\ See, e.g., Notice of Technical Conference, AD19-12-000, at
1 (Feb. 4, 2019), and Supplemental Notice of Technical Conference,
AD19-12-000, at 1 (Mar. 1, 2019); Supply Chain Risk Management
Reliability Standards, Order No. 850, 83 FR 53992 (Oct. 26, 2018),
165 FERC ] 61,020 (2018); Cyber Security Incident Reporting
Reliability Standards, Order No. 848, 83 FR 36727 (July 31, 2018),
164 FERC ] 61,033 (2018); see also Extraordinary Expenditures
Necessary to Safeguard National Energy Supplies, 96 FERC ] 61,299
(2001) (providing assurances, following the events of September 11,
2001, that the Commission will approve applications to recover
prudently incurred costs necessary to safeguard the reliability and
security of the nation's energy supply infrastructure).

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    (Q 32) Should the Commission incentivize physical and cyber-
security enhancements at transmission facilities? If so, what types of
security investments should qualify for transmission incentives? What
type of incentive(s) would be appropriate?
    (Q 33) How should the Commission define ``security'' in the context
of determining eligibility for incentive treatment? For example, should
the Commission define security based on specific investments or based
on performance of delivering increased security of the transmission
system?
6. Resilience
    28. The Commission has proposed to define ``resilience'' as ``the
ability to withstand and reduce the magnitude and/or duration of
disruptive events, which includes the capability to anticipate, absorb,
adapt to, and/or rapidly recover from such an event.'' \34\ So defined,
enhancements to the resilience of the transmission system may enhance
its overall reliability, potentially bringing investments in resilience
within the Commission's mandate under section 219.
---------------------------------------------------------------------------

    \34\ Grid Reliability and Resilience Pricing and Grid Resilience
in Regional Transmission Organizations and Independent System
Operators, 162 FERC ] 61,012, at P 23 (2018).
---------------------------------------------------------------------------

    (Q 34) Should transmission projects that enhance resilience be
eligible for incentives based upon their reliability-enhancing
attributes?
    (Q 35) If so, how could the Commission consider or measure the
benefits of an individual project towards grid resilience?
    (Q 36) If the Commission were to grant incentives for measures that
enhance the resilience of the transmission system, what incentive(s)
would be appropriate?
7. Improving Existing Transmission Facilities
    29. Section 219(b)(3) directs the Commission to encourage
investments in technologies and other measures that increase the
capacity and efficiency of existing transmission facilities and improve
the operation of those facilities.\35\ Such investments could include
advanced management software or application of technologies, such as
energy storage, in order to improve utilization of existing
transmission system assets.
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    \35\ 16 U.S.C. 824s(b)(3).
---------------------------------------------------------------------------

    (Q 37) How should the Commission incentivize the deployment of
technologies and other measures to enhance the capacity, efficiency,
and operation of the transmission grid? How can the Commission identify
and quantify how a technology or other measure contributes to those
goals? Please provide examples.
    (Q 38) Can the Commission distinguish between incremental
improvements that merit an incentive and those maintenance-related
expenses that a transmission owner would make in its ordinary course of
business?
    (Q 39) How should a transmission owner seeking this type of
incentive demonstrate increases or improvements in the capabilities or
operations of existing transmission facilities?
    (Q 40) Should the Commission provide a stand-alone, transmission
technology-related incentive? If the Commission provides a stand-alone
transmission technology-related incentive, what criteria should be
employed for a technology to be considered as meriting an incentive?
Should the Commission periodically revisit the definition of an
eligible technology?
    (Q 41) Certain utility costs, such as those associated with grid
management technology, including dynamic line rating technology, are
typically recovered through operations and maintenance expenses within
cost-of service rates. For such costs, should the Commission, instead,
consider inclusion of these expenses in rate base as a regulatory
asset? If so, what costs should be eligible for such treatment and over
what period should they be amortized?
    (Q 42) Are there ways the Commission could incentivize RTOs/ISOs to
adopt better grid management technologies and/or other technologies to
improve the efficiency of individual transmission assets to promote
efficient use of the transmission system and improved market
performance?
    (Q 43) Should the Commission interpret section 219(b)(3) to
encourage improvements that are not historically considered part of the
transmission system, such as, for example, software upgrades,
technologies that allow for faster ramping, or other innovative
measures that achieve the same goals as new transmission facilities?
What types of incentives could increase the adoption of these
technologies? Are there forms of performance-based ratemaking with
respect to transmission that the Commission should explore? If so,
describe such alternative ratemaking structures.
8. Interregional Transmission Projects
    30. An interregional transmission project \36\ has the potential to
improve interregional coordination, help to eliminate seams issues, and
provide more efficient power flow among regions. Although Order No.
1000 required coordination among neighboring transmission planning
regions to identify potential interregional transmission facilities,
such projects have been scarce to date.
---------------------------------------------------------------------------

    \36\ Order No. 1000 defined an interregional transmission
facility as one that is physically located in two or more
neighboring transmission planning regions. Order No. 1000, 136 FERC
] 61,051 at P 63.
---------------------------------------------------------------------------

    (Q 44) Should the Commission use incentives to encourage the
development of interregional transmission projects? How, if at all,
would any such incentive interact with Order No. 1000's reforms?
    (Q 45) If the Commission should use incentives to encourage
interregional transmission projects, should all interregional projects
be eligible or should it be based on some other criteria? How should
the Commission consider the benefits of an individual interregional
transmission project?
    (Q 46) If the Commission were to grant incentives for interregional
transmission projects, what incentive(s) would be appropriate?
9. Unlocking Locationally Constrained Resources
    31. The 2012 Incentives Policy Statement provided that ``projects
that unlock location constrained generation resources that previously
had limited or no access to the wholesale electricity markets'' may be
eligible for incentives.\37\ In subsequent years, interconnection
queues in many regions of the country have expanded considerably, with
many of the potential resources clustered in specific geographic areas
with limited transmission access.\38\
---------------------------------------------------------------------------

    \37\ 2012 Incentives Policy Statement, 141 FERC ] 61,129 at P
21.
    \38\ For instance, Midcontinent Independent System Operator,
Inc., as of February 28, 2019, had 70.3 GWs of active projects in
its interconnection queue. See https://cdn.misoenergy.org/GIQ%20Web%20Overview272899.pdf.
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    (Q 47) Should the Commission use incentives to encourage the
development of transmission projects that will facilitate the
interconnection of large amounts of resources?
    (Q 48) If so, what metrics could the Commission consider when
evaluating whether a transmission project

facilitates the interconnection of generation?
    (Q 49) Should such an incentive focus on resources already in the
queue, a region's potential for new resources, or some other measure?
How could the Commission evaluate the potential for further resource
development in a particular geographic area?
10. Ownership by Non-Public Utilities
    32. Section 219(b)(1) encourages the Commission to facilitate
capital investment in transmission infrastructure, regardless of the
ownership of those facilities.
    (Q 50) Are there barriers to non-public utilities' ownership of
transmission facilities?
    (Q 51) Should the Commission consider granting incentives to
promote joint ownership arrangements with non-public utilities and, if
so, how?
11. Order No. 1000 Transmission Projects
    33. The Commission has considered whether it could reduce
transmission developer risk by granting blanket pre-approval (i.e., a
rebuttable presumption) of three risk-reducing incentives for
transmission projects selected in a regional transmission plan for
purposes of cost allocation: CWIP, abandoned plant, and regulatory
asset treatment.\39\
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    \39\ See Notice Inviting Post-Technical Conference Comments,
Docket No. AD16-18-000, at 2 (Aug. 3, 2016).
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    (Q 52) Should these or other incentives be granted automatically
for transmission projects selected in a regional transmission plan for
purposes of cost allocation?
    (Q 53) If so, what specific incentives are appropriate for such
automatic treatment and how should such incentives be designed?
    34. Following Order No. 1000, the Commission has exercised it
discretion to grant certain incentives to non-incumbent transmission
developers under section 205 of the FPA, in order to further the public
policy goal of placing non-incumbent transmission developers on a level
playing field with incumbent transmission owners in Order No. 1000
regional transmission planning processes.\40\
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    \40\ See, e.g., PJM Interconnection, L.L.C., 155 FERC ] 61,097,
at P 175 (2016), order on reh'g, 158 FERC ] 61,060 (2017); ATX Sw.,
LLC, 152 FERC ] 61,193, at PP 18, 23 (2015); Transource Kan., LLC,
151 FERC ] 61,010, at P 19 (2015), order on reh'g, 154 FERC ]
61,011, at P 12 (2016), petition dismissed sub nom, Kan. Corp.
Comm'n v. FERC, 881 F.3d 924 (D.C. Cir. 2018); Xcel Energy Sw.
Transmission Co., LLC, 149 FERC ] 61,182, at P 33 (2014).
---------------------------------------------------------------------------

    (Q 54) Should the Commission continue to use certain incentives to
seek to place non-incumbent transmission developers on a level playing
field with incumbent transmission owners in Order No. 1000 regional
transmission planning processes? If so, should the Commission consider
requests for such incentives under section 205, or should the
Commission consider requests for such incentives for non-incumbent
transmission owners under section 219?
12. Transmission Projects in Non-RTO/ISO Regions
    35. Applications for transmission incentives to date have almost
exclusively been for transmission projects proposed to be developed
within RTOs/ISOs.
    (Q 55) Are there factors that discourage developers of transmission
projects in non-RTO/ISO regions from seeking incentives?
    (Q 56) What, if any, additional types of incentives could
appropriately encourage the development of transmission in non-RTO/ISO
regions?

C. Existing Incentives

    36. The Commission also seeks comment on the types of incentives
that it has awarded to date, including ROE adder incentives based on
risks and challenges, discussed above. Commenters should address
whether the incentive itself remains relevant and appropriate. In
addition, commenters should consider whether the goals underlying the
incentive could be incentivized more efficiently. For example, if an
incentive is currently awarded as ROE basis point adder, Commenters
should also address whether a non-ROE incentive would be more
appropriate. Although we invite comment on all current incentives, we
specifically seek comment on the following incentives.
1. ROE-Adder Incentives
a. Transmission-Only Companies
    37. In Order No. 679, the Commission found that transmission-only
companies (i.e., Transcos) warranted incentives because they were
willing and able to invest in transmission based on a proven and
encouraging track record of existing Transcos' investment in
transmission infrastructure and their expansion plans. The Commission
explained that this record of investment was due to the stand-alone
nature of these entities--``[b]y eliminating competition for capital
between generation and transmission functions and thereby maintaining a
singular focus on transmission investment, the Transco model responds
more rapidly and precisely to market signals indicating when and where
transmission investment is needed.'' \41\ Further, the Commission found
that ``Transcos have no incentive to maintain congestion in order to
protect their owned generation''; ``Transcos' for-profit nature,
combined with a transmission-only business model, enhances asset
management and access to capital markets and provides greater
incentives to develop innovative services''; and due to ``their stand-
alone nature, Transcos also provide non-discriminatory access to all
grid users,'' and supported regional planning goals.\42\ In subsequent
decisions regarding the Transco adder, the Commission has addressed
challenges presented by maintaining an appropriate threshold for
eligibility with respect to necessary independence.\43\
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    \41\ Order No. 679, 116 FERC ] 61,057 P 224.
    \42\ Id. PP 224-227.
    \43\ See, e.g., Consumers Energy Co. v. Int'l Transmission Co.,
165 FERC ] 61,021, at PP 67-73 (2018) (reducing a previously granted
Transco ROE adder due to reduced independence); NextEra Energy
Transmission N.Y. Inc., 162 FERC ] 61,196, at PP 51-52 (2018)
(finding that the applicants relationship with affiliated market
participants did not prevent it from meeting the independence
standard for a Transco).
---------------------------------------------------------------------------

    (Q 57) Does the Transco business model continue to provide
sufficient benefits to merit transmission incentives? What information
should an entity seeking a Transco incentive provide to demonstrate
sufficient benefits?
    (Q 58) Should the Transco incentive remain available to Transcos
that are affiliated with a market participant? If so, how should the
Commission evaluate whether a Transco is sufficiently independent to
merit an incentive? \44\
---------------------------------------------------------------------------

    \44\ C.f. Consumers Energy Co. v. Int'l Transmission Co., 165
FERC ] 61,021 at PP 67-74 (granting a complaint in part to reduce
Transco adders based upon the Commission's finding that the Transco
was now less independent).
---------------------------------------------------------------------------

    (Q 59) Should a Transco incentive be awarded on a project-by-
project basis?
    (Q 60) Should the Transco incentive exclude assets that a Transco
buys, rather than develops?
b. RTO/ISO Participation
    38. Section 219(c) requires that the Commission provide incentives
to transmitting utilities or electric utilities that join an RTO or
ISO. In Order No. 679, the Commission found that ROE incentives should
be granted to utilities that ``join and/or continue to be a member of
an ISO, RTO, or other Commission-approved Transmission Organization.''
\45\ The Commission declined to make a finding on the appropriate size
or duration of the

incentive.\46\ Subsequently, the U.S. Court of Appeals for the Ninth
Circuit found that the Commission's granting of an RTO participation
incentive to Pacific Gas and Electric Co. (PG&E) was arbitrary and
capricious in its application of Order Nos. 679 and 679-A because the
Commission failed to provide a reasoned explanation for granting the
incentive in light of the Commission's longstanding policy that
incentives should only be granted to induce future behavior.\47\
---------------------------------------------------------------------------

    \45\ Order No. 679, 116 FERC ] 61,057 at P 326.
    \46\ Id. P 331.
    \47\ Cal. Pub. Util. Comm'n v. FERC, 879 F.3d at 974-75, 977;
see also Pacific Gas and Electric Co., 164 FERC ] 61,121 (2018)
(establishing a briefing schedule to supplement the record on the
specific questions raised on remand).
---------------------------------------------------------------------------

    (Q 61) Should the Commission revise the RTO-participation
incentive?
    (Q 62) Should the Commission consider providing incentives other
than ROE adders for utilities that join RTO/ISOs, such as the automatic
provision of CWIP in rate base or the abandoned plant incentive \48\
for all transmission-owning members of an RTO/ISO? If so, what other
types of incentives would be appropriate?
---------------------------------------------------------------------------

    \48\ The abandoned plant incentive allows recovery of 100
percent of the prudently incurred costs of transmission facilities
that are cancelled or abandoned due to factors beyond the control of
the public utility.
---------------------------------------------------------------------------

    (Q 63) If the Commission continues to provide ROE adders for RTO/
ISO participation, what is an appropriate level for an ROE adder?
    (Q 64) Should the RTO-participation incentive be awarded for a
fixed period of time after a transmission owner joins an RTO or ISO?
    (Q 65) Should the RTO-participation adder be awarded on a project-
specific basis?
    (Q 66) In Order No. 679, the Commission found that ``the basis for
the incentive is a recognition that benefits flow from membership in
such organizations and the fact that continuing membership is generally
voluntary.'' \49\ Should voluntary participation remain a requirement
for receiving RTO/ISO incentives?
---------------------------------------------------------------------------

    \49\ Order No. 679, 116 FERC ] 61,057 at P 331.
---------------------------------------------------------------------------

c. Advanced Technology
    39. Order No. 679, the Commission considered the use of advanced
technologies (1) as part of an overall nexus, accounting for risks and
challenges, and (2) where an applicant sought a stand-alone incentive
ROE adder based on advanced technology utilization. The Commission
discontinued a stand-alone advanced transmission technologies incentive
in the 2012 Incentives Policy Statement, but concluded that some
transmission enhancement projects might represent good candidates for
an ROE adder for risks and challenges.\50\ To date, there have been few
applications seeking an ROE adder related to advanced technology.
---------------------------------------------------------------------------

    \50\ 2012 Incentives Policy Statement, 141 FERC ] 61,129 at P 21
& nn.27-28.
---------------------------------------------------------------------------

    (Q 67) Why have few transmission developers sought transmission
incentives for the adoption of advanced technology?
    (Q 68) Do NERC reliability standards affect the willingness of
transmission developers to enhance existing transmission facilities by
deploying new technologies because of concerns these technologies may
increase the risk of standards violations?
    (Q 69) Are there any types of transmission incentives that could
better encourage deployment of new technologies? If so, please describe
them.
2. Non-ROE Transmission Incentives
a. Regulatory Asset/Deferred Recovery of Pre-Commercial Costs and CWIP
    40. In Order No. 679, the Commission recognized that some
transmission incentives--such as including 100 percent of CWIP in rate
base and recovery of 100 percent of pre-commercial costs as an expense
or as a regulatory asset--reduce the financial and regulatory risks
associated with transmission investment.\51\
---------------------------------------------------------------------------

    \51\ These incentives have routinely been granted to applicants
who do not yet have customers from which to recover pre-commercial
costs, including costs associated with Order No. 1000 proposals by
nonincumbent transmission developers. The Commission has reasoned
that doing so is necessary to level the playing field with incumbent
transmission owners, who can already recover such costs from
ratepayers. See Ne. Transmission Dev., LLC, 155 FERC ] 61,097, at P
41 (2016), order on reh'g, 158 FERC ] 61,060 (2017); Xcel Energy Sw.
Transmission Co., LLC, 149 FERC ] 61,182 at P 33.
---------------------------------------------------------------------------

    (Q 70) Should the Commission continue to provide regulatory asset
treatment and CWIP as incentives? Should these incentives be granted
automatically to certain types of transmission projects? If so, how
would the Commission determine what types of transmission projects?
    (Q 71) Should the costs of unsuccessful Order No. 1000 proposals be
recoverable through regulatory asset and deferred pre-commercial cost
recovery incentives? If so, what costs are appropriate for recovery?
b. Hypothetical Capital Structure
    41. A hypothetical capital structure can serve as an incentive by
providing cash flow predictability and a higher rate of return where
public utilities have a higher amount of debt than in the hypothetical
capital structure. The Commission largely relies on a public utility's
actual capitalization in setting its rate of return, but recognized in
Order No. 679 that an overly rigid approach to evaluating a proposed
capital structure could be a disincentive to investment in new
transmission projects.\52\ Accordingly, the Commission allows
applicants to file an overall rate of return based on a hypothetical
capital structure, and gives them the flexibility to refinance or
employ different capitalizations as may be needed to maintain the
viability of new capacity additions. The Commission currently approves
hypothetical capital structures during the construction period, chiefly
for small or new transmission owners for which the new transmission
project would cause substantial fluctuations in their capital structure
during construction. The Commission has allowed a hypothetical capital
structure to extend for the life of the transmission project for non-
public utilities without traditional capital structures.
---------------------------------------------------------------------------

    \52\ Order No. 679, 116 FERC ] 61,057 at PP 123, 131.
---------------------------------------------------------------------------

    (Q 72) Should the Commission continue to utilize hypothetical
capital structures as a transmission incentive? If so, what entities
should be eligible to apply for a hypothetical capital structure?
    (Q 73) Have hypothetical capital structures been effective in
reducing the overall cost of debt by rendering the capital structure
more predictable?
    (Q 74) In what circumstances, if any, should hypothetical capital
structure incentives granted to an entity also be authorized for that
entity's yet-to-be formed affiliates?
    (Q 75) Under what circumstances, if any, should hypothetical
capital structures extend beyond the construction period?
    (Q 76) Should the Commission provide a consistent hypothetical
structure (e.g., 50 percent debt and 50 percent equity)? Alternatively,
should the Commission cap the equity percentage at some upper limit
(e.g., 50 percent)?
c. Recovery of the Cost of Abandoned Plant
    42. Even prior to Order No. 679, the Commission granted recovery of
100 percent of the prudently incurred costs of transmission facilities
that are cancelled or abandoned due to factors beyond the control of
the public utility (the abandoned plant incentive) as a way of
mitigating certain risks that are

outside the control of the developer.\53\ Order No. 679 stated that
transmission developers may be entitled to recover 100 percent of the
prudently incurred costs related to certain transmission facilities if
such facilities are later abandoned or cancelled.\54\
---------------------------------------------------------------------------

    \53\ See Order No. 679, 116 FERC ] 61,057 at P 156 (explaining
that the Commission's proposed change in policy was an extension of
the Commission's decision in S. Cal. Edison Co., 112 FERC ] 61,014,
reh'g denied, 113 FERC ] 61,143 (2005)).
    \54\ Id. P 163.
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    (Q 77) Should the Commission grant the abandoned plant incentive
automatically, rather than on a case-by-case basis? Under what
circumstances might an automatic award of the abandoned plant incentive
be appropriate?
    (Q 78) How, if at all, could the Commission grant the abandoned
plant incentive without encouraging transmission developers to pursue
unnecessarily risky transmission projects or take unnecessary risks in
transmission development? Could such behavior be reduced if the
developer shared some risk associated with the abandonment, e.g., 10
percent of abandonment costs? If so, what level of developer risk is
appropriate?
    (Q 79) How should the Commission evaluate whether the costs of an
abandoned facility were prudently incurred?
d. Accelerated Depreciation
    43. In Order No. 679, the Commission included accelerated
depreciation as a potential transmission incentive reasoning that this
incentive increases cash flow, providing an incentive to undertake
transmission projects.
    (Q 80) Should the Commission continue to consider accelerated
depreciation as an incentive?
    (Q 81) Does the accelerated deprecation incentive provide
meaningful benefits to transmission developers?
    (Q 82) Should the Commission grant an accelerated depreciation
incentive with a generic depreciation period or continue to determine
such a period on a case-by-case basis?

D. Mechanics and Implementation

1. Duration of Incentives
    44. The Commission is considering whether incentives should be
revisited if there is a material modification to the project or a
significant change in the expected benefits. Please comment on whether
particular types of incentives should automatically sunset and under
what certain circumstances.
    (Q 83) Should the Commission limit the duration of a granted
transmission incentive? If so, should this limit be based on the type
of incentive granted?
    (Q 84) How should the Commission structure a durational component
to its incentives? For example, should the Commission provide that
transmission incentives automatically sunset after a certain period?
\55\
---------------------------------------------------------------------------

    \55\ For example, the incentive for joining an RTO/ISO or
forming a Transco could be limited to a set number of years.
---------------------------------------------------------------------------

    (Q 85) Should the Commission provide that a transmission incentive
can be eliminated or modified upon a material change to the
transmission project? How would such an elimination or modification be
implemented? What should constitute such a material change? How would
the Commission and interested parties be informed of such a material
change?
    (Q 86) Should there be a process of measurement and verification
(or audit) to determine if the expected benefits accrued to consumers?
    (Q 87) If so, how should measurement and verification take place
and over what time period?
    (Q 88) Should the Commission consider eliminating an incentive if
the project fails to realize its anticipated benefits?
    (Q 89) Should there be reporting on projects' expected benefits
compared to results, and over what time period?
2. Case-by-Case vs. Automatic Approach in Reviewing Incentive
Applications
    45. In Order No. 679, the Commission stated that the section 219(a)
threshold that a transmission project must ensure reliability or reduce
the cost of delivered power by reducing transmission congestion and the
nexus test are not prescriptive by design, and are intended to be
applied on a case-by-case basis.
    (Q 90) What are the benefits and drawbacks of granting incentives
on a case-by-case basis, as compared to being granted automatically,
with or without related threshold criteria? Would an automatic approach
based on established threshold criteria provide additional certainty?
If so, how?
    (Q 91) If so, how could the Commission determine which incentives
should be awarded automatically?
    (Q 92) If the existing case-by-case approach to incentives is
retained, could it be improved? If so, how?
3. Interaction Between Different Potential Incentives in Determining
Correct Level of ROE Incentives
    46. In determining whether an applicant has satisfied the nexus
test, the Commission evaluates the interrelationship between the
requested incentives.\56\ The Commission, however, to date has provided
limited guidance regarding what level of transmission incentives should
be provided or how to ensure that the combination of transmission
incentives provided is appropriate and produces rates that are just and
reasonable.\57\
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    \56\ Order No. 679-A, 117 FERC ] 61,345 at P 21.
    \57\ An exception, as noted, is that the Commission has required
applicants to seek to employ risk reducing incentives before they
seek an ROE adder for risks and challenges. See 2012 Incentives
Policy Statement, 141 FERC ] 61,129 at PP 24, 28-29.
---------------------------------------------------------------------------

    (Q 93) Should the Commission establish a more formulaic framework
for determining the appropriate level and combination of incentives? If
such a framework is created, what elements should it include?
    (Q 94) Alternatively, if the Commission continues evaluating
incentive requests on a case-by-case basis, how could the Commission
provide more detailed explanations in individual cases to better
describe how it derives the appropriate level and combination of
incentives? If so, what elements should such explanations provide?
    (Q 95) The Commission's current policy is that the total ROE may
not exceed the zone of reasonableness. If a transmission project
qualifies for ROE incentives, should there be an upper limit or range
that the total ROE cannot exceed? If so, what is the appropriate limit
or range? Should this vary based on how the Commission sets base ROE?
\58\
---------------------------------------------------------------------------

    \58\ The Commission has proposed a methodology for base ROE and
established a paper hearing proceeding on whether and how this
methodology should apply. See Martha Coakley v. Bangor Hydro-Elec.
Co., 165 FERC ] 61,030 (2018); Ass'n of Businesses Advocating Tariff
Equity v. Midcontinent Indep. Sys. Operator, Inc., 165 FERC ] 61,118
(2018).
---------------------------------------------------------------------------

4. Bounds on ROE Incentives
    47. The benefits of various transmission projects may vary
substantially and, in some cases, be difficult to compare. Particularly
given the current risks and challenges framework, the Commission has
maintained discretion to determine the level of any granted incentive
ROE rather than establishing pre-determined levels or ranges for
incentive ROEs.
    (Q 96) For ROE incentives, to what extent, if any, should the
Commission retain discretion to determine the appropriate level of ROE
incentives?
    (Q 97) If the Commission retains discretion with respect to
determining ROE incentives, should its discretion be bound within a
pre-determined range

(e.g., between 50 and 100 basis points)? If so, what is the appropriate
range and why?

E. Metrics for Evaluating the Effectiveness of Incentives

    48. The Commission has a ``longstanding policy that incentives
should only be awarded to induce voluntary conduct.'' \59\
Nevertheless, it can sometimes be difficult to identify the extent to
which a particular incentive motivates a transmission developer to take
a particular action. Order No. 679 adopted an annual reporting
requirement, Form FERC-730, which requires transmission incentives
recipients to provide limited information.\60\ Additional transmission
incentive-related data, beyond that available under the Commission's
existing reporting standards or through other public sources, could
help the Commission to better understand the effectiveness of the
incentives program, including the effects of any changes that it adopts
through this proceeding. In particular, a standard of comparison among
transmission projects, regardless of whether a project receives
incentives and/or ultimately goes into service, would allow the
Commission to examine whether incentives motivate investment in and
development of new transmission projects.
---------------------------------------------------------------------------

    \59\ Cal. Pub. Util. Comm'n v. FERC, 879 F.3d at 978.
    \60\ Order No. 679, 116 FERC ] 61,057 at P 367. FERC-730
requests information concerning: (1) The transmission developer's
actual capital spending on each transmission project for which it
has received incentives, as well as its projected capital spending
on the projects for the next five years; (2) a high-level
description of such projects, including their voltage level; (3) the
type of transmission project (i.e., whether it is new build, an
upgrade to existing infrastructure, a refurbishment/replacement, or
a generator direct connection); (4) each project's completion status
(i.e., complete, under construction, pre-engineering, planned,
proposed, or conceptual); and (5) each project's estimated
completion date, as well as the reason for any delays (i.e., siting,
permitting, construction, delayed completion of new generator, or
other).
---------------------------------------------------------------------------

    (Q 98) What metrics should the Commission use in measuring the
effectiveness of incentives, e.g., if certain milestones are reached or
only if a transmission project is built and energized?
    (Q 99) Should the obligation to file Form FERC-730 be expanded to
all public utility transmission providers?
    (Q 100) Should the Commission require that incentive recipients
provide additional data through Form FERC-730? If so, what additional
information should be provided?
    (Q 101) For each transmission project, should the Commission
require additional data such as the primary driver of each transmission
project (e.g., reliability needs) and the risks entailed in its
development (e.g., number of permits required, siting challenges)?
    (Q 102) If a transmission project is abandoned, should the
Commission require additional data such as the reasons that it failed
(e.g., lack of financing, inability to obtain permits, the need for the
transmission project did not materialize or was addressed through other
means)?
    (Q 103) Should the information on annual transmission spending
associated with projects that received transmission incentives be
broken down by transmission project?
    (Q 104) How burdensome would such information requirements be? To
ensure that any reporting is not unduly burdensome, should the
Commission adopt some type of reporting threshold, such as a voltage,
mileage, or dollar threshold, to limit the transmission projects on
which it collects information?
    (Q 105) Should the Commission upgrade the FERC-730 filing format to
XBRL or another format or standard? If so, what filing format would be
most beneficial and useful to filers and users of the information?

III. Comment Procedures

    49. The Commission invites interested persons to submit comments on
the matters and issues proposed in this Notice of Inquiry, including
any related matters or alternative proposals that commenters may wish
to discuss. Initial Comments are due June 25, 2019, and Reply Comments
are due July 25, 2019. Comments must refer to Docket No. PL19-3-000,
and must include the commenter's name, the organization they represent,
if applicable, and their address in their comments.
    50. The Commission encourages comments to be filed electronically
via the eFiling link on the Commission's website at http://www.ferc.gov. The Commission accepts most standard word processing
formats. Documents created electronically using word processing
software should be filed in native applications or print-to-PDF format
and not in a scanned format. Commenters filing electronically do not
need to make a paper filing.
    51. Commenters that are not able to file comments electronically
must send an original of their comments to: Federal Energy Regulatory
Commission, Secretary of the Commission, 888 First Street NE,
Washington, DC 20426.
    52. All comments will be placed in the Commission's public files
and may be viewed, printed, or downloaded remotely as described in the
Document Availability section below. Commenters on this proposal are
not required to serve copies of their comments on other commenters.

IV. Document Availability

    53. In addition to publishing the full text of this document in the
Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
internet through the Commission's Home Page (http://www.ferc.gov) and
in the Commission's Public Reference Room during normal business hours
(8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street NE, Room 2A,
Washington DC 20426.
    54. From the Commission's Home Page on the internet, this
information is available on eLibrary. The full text of this document is
available on eLibrary in PDF and Microsoft Word format for viewing,
printing, and/or downloading. To access this document in eLibrary, type
the docket number excluding the last three digits of this document in
the docket number field.
    55. User assistance is available for eLibrary and the Commission's
website during normal business hours from the Commission's Online
Support at<PHONE_NUMBER> (toll free at 1-866-208-3676) or email at
<EMAIL_ADDRESS>or the Public Reference Room at (202) 502-
8371, TTY<PHONE_NUMBER>. Email the Public Reference Room at
<EMAIL_ADDRESS>
    By direction of the Commission.

    Issued: March 21, 2019.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
[FR Doc. 2019-05895 Filed 3-27-19; 8:45 am]
 BILLING CODE 6717-01-P


DATE: 	May 2023

SUBJECT: 	HEM Model Output Files for the Neoprene Production Source Category

FROM: 	Matt Woody
	U.S. EPA, OAQPS

TO: 	EPA Docket ID EPA-HQ-OAR-2022-0730

We are placing these files in the docket for this rulemaking because they have been provided to Denka Performance Elastomer, LLC in response to a Request for Production in United States of America v. Denka Performance Elastomer, LLC et al., No. 2:23-cv-00735-CJB-MBN (E.D. La.). This information is already contained in this docket in the form of input files, but we are providing the output files as well. Attached to this memo are the model output files for the Neoprene Production Source Category Actual Post-Control Emissions. Other model output files available in the docket include:
Neoprene Production Source Category Actual Baseline Emissions
Neoprene Production Source Category Acute Emissions
Neoprene Production Source Category Whole Facility Baseline Emissions
Neoprene Production Source Category Whole Facility Post-Control Emissions


[Federal Register Volume 75, Number 40 (Tuesday, March 2, 2010)]
[Notices]
[Pages 9478-9480]
[FR Doc No: 2010-4255]

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DEPARTMENT OF TRANSPORTATION

Federal Motor Carrier Safety Administration

[Docket ID FMCSA-2009-0291]

Qualification of Drivers; Exemption Applications; Vision

AGENCY: Federal Motor Carrier Safety Administration (FMCSA), DOT.

ACTION: Notice of final disposition.

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

SUMMARY: FMCSA announces its decision to exempt 24 individuals from the
vision requirement in the Federal Motor Carrier Safety Regulations
(FMCSRs). The exemptions will enable these individuals to operate
commercial motor vehicles (CMVs) in interstate commerce without meeting
the prescribed vision standard. The Agency has concluded that granting
these exemptions will provide a level of safety that is equivalent to,
or greater than, the level of safety maintained without the exemptions
for these CMV drivers.

DATES: The exemptions are effective March 2, 2010. The exemptions
expire on March 2, 2012.

FOR FURTHER INFORMATION CONTACT: Dr. Mary D. Gunnels, Director, Medical
Programs,<PHONE_NUMBER><EMAIL_ADDRESS>FMCSA, Department of
Transportation, 1200 New Jersey Avenue, SE., Room W64-224, Washington,
DC 20590-0001. Office hours are from 8:30 a.m. to 5 p.m. Monday through
Friday, except Federal holidays.

SUPPLEMENTARY INFORMATION:

Electronic Access

    You may see all the comments online through the Federal Document
Management System (FDMS) at http://www.regulations.gov.
    Docket: For access to the docket to read background documents or
comments, go to http://www.regulations.gov at any time or Room W12-140
on the ground level of the West Building, 1200 New Jersey Avenue, SE.,
Washington, DC, between 9 a.m. and 5 p.m., Monday through Friday,
except Federal holidays. The FDMS is available 24 hours each day, 365
days each year. If you want acknowledgment that we received your
comments, please include a self-addressed, stamped envelope or postcard
or print the acknowledgment page that appears after submitting comments
on-line.
    Privacy Act: Anyone may search the electronic form of all comments
received into any of our dockets by the name of the individual
submitting the comment (or of the person signing the comment, if
submitted on behalf of an association, business, labor union, etc.).
You may review the DOT's complete Privacy Act Statement in the Federal
Register published on April 11, 2000 (65 FR 19476). This information is
also available at http://www.regulations.gov.

Background

    On December 11, 2009, FMCSA published a notice of receipt of
exemption applications from certain individuals, and requested comments
from the public (74 FR 65842). That notice listed 24 applicants' case
histories. The 24 individuals applied for exemptions from the vision
requirement in 49 CFR 391.41(b)(10), for drivers who operate CMVs in
interstate commerce.
    Under 49 U.S.C. 31136(e) and 31315, FMCSA may grant an exemption
for a 2-year period if it finds ``such exemption would likely achieve a
level of safety that is equivalent to, or greater than, the level that
would be achieved absent such exemption.'' The statute also allows the
Agency to renew exemptions at the end of the 2-year period.
Accordingly, FMCSA has evaluated the 24 applications on their merits
and made a determination to grant exemptions to all of them.

Vision and Driving Experience of the Applicants

    The vision requirement in the FMCSRs provides:
    A person is physically qualified to drive a commercial motor
vehicle if that person has distant visual acuity of at least 20/40
(Snellen) in each eye without corrective lenses or visual acuity
separately corrected to 20/40 (Snellen) or better with corrective
lenses, distant binocular acuity of a least 20/40 (Snellen) in both
eyes with or without corrective lenses, field of vision of at least
70[deg] in the horizontal meridian in each eye, and the ability to
recognize the colors of traffic signals and devices showing standard
red, green, and amber (49 CFR 391.41(b)(10)).
    FMCSA recognizes that some drivers do not meet the vision standard,
but have adapted their driving to accommodate their vision limitation
and demonstrated their ability to drive safely. The 24 exemption
applicants listed in this notice are in this category. They are unable
to meet the vision standard in one eye for various reasons, including
amblyopia, aphakia, corneal scarring, glaucoma, prosthesis, retinal
detachment, macular scarring, optic atrophy, myopic astigmatism, and
loss of vision due to trauma. In most cases, their eye conditions were
not recently developed. All but 14 of the applicants

were either born with their vision impairments or have had them since
childhood. The 14 individuals who sustained their vision conditions as
adults have had them for periods ranging from 5 to 48 years.
    Although each applicant has one eye which does not meet the vision
standard in 49 CFR 391.41(b)(10), each has at least 20/40 corrected
vision in the other eye, and in a doctor's opinion, has sufficient
vision to perform all the tasks necessary to operate a CMV. Doctors'
opinions are supported by the applicants' possession of valid
commercial driver's licenses (CDLs) or non-CDLs to operate CMVs. Before
issuing CDLs, States subject drivers to knowledge and skills tests
designed to evaluate their qualifications to operate a CMV.
    All these applicants satisfied the testing standards for their
State of residence. By meeting State licensing requirements, the
applicants demonstrated their ability to operate a commercial vehicle,
with their limited vision, to the satisfaction of the State.
    While possessing a valid CDL or non-CDL, these 24 drivers have been
authorized to drive a CMV in intrastate commerce, even though their
vision disqualified them from driving in interstate commerce. They have
driven CMVs with their limited vision for careers ranging from 7 to 28
years. In the past 3 years, six of the drivers had convictions for
traffic violations and three of the drivers were involved in crashes.
    The qualifications, experience, and medical condition of each
applicant were stated and discussed in detail in the December 11, 2009
notice (74 FR 65842).

Basis for Exemption Determination

    Under 49 U.S.C. 31136(e) and 31315, FMCSA may grant an exemption
from the vision standard in 49 CFR 391.41(b)(10) if the exemption is
likely to achieve an equivalent or greater level of safety than would
be achieved without the exemption. Without the exemption, applicants
will continue to be restricted to intrastate driving. With the
exemption, applicants can drive in interstate commerce. Thus, our
analysis focuses on whether an equal or greater level of safety is
likely to be achieved by permitting each of these drivers to drive in
interstate commerce as opposed to restricting him or her to driving in
intrastate commerce.
    To evaluate the effect of these exemptions on safety, FMCSA
considered not only the medical reports about the applicants' vision,
but also their driving records and experience with the vision
deficiency.
    To qualify for an exemption from the vision standard, FMCSA
requires a person to present verifiable evidence that he/she has driven
a commercial vehicle safely with the vision deficiency for the past 3
years. Recent driving performance is especially important in evaluating
future safety, according to several research studies designed to
correlate past and future driving performance. Results of these studies
support the principle that the best predictor of future performance by
a driver is his/her past record of crashes and traffic violations.
Copies of the studies may be found at docket number FMCSA-1998-3637.
    We believe we can properly apply the principle to monocular
drivers, because data from the Federal Highway Administration's (FHWA)
former waiver study program clearly demonstrate the driving performance
of experienced monocular drivers in the program is better than that of
all CMV drivers collectively (See 61 FR 13338, 13345, March 26, 1996).
The fact that experienced monocular drivers demonstrated safe driving
records in the waiver program supports a conclusion that other
monocular drivers, meeting the same qualifying conditions as those
required by the waiver program, are also likely to have adapted to
their vision deficiency and will continue to operate safely.
    The first major research correlating past and future performance
was done in England by Greenwood and Yule in 1920. Subsequent studies,
building on that model, concluded that crash rates for the same
individual exposed to certain risks for two different time periods vary
only slightly (See Bates and Neyman, University of California
Publications in Statistics, April 1952). Other studies demonstrated
theories of predicting crash proneness from crash history coupled with
other factors. These factors--such as age, sex, geographic location,
mileage driven and conviction history--are used every day by insurance
companies and motor vehicle bureaus to predict the probability of an
individual experiencing future crashes (See Weber, Donald C.,
``Accident Rate Potential: An Application of Multiple Regression
Analysis of a Poisson Process,'' Journal of American Statistical
Association, June 1971). A 1964 California Driver Record Study prepared
by the California Department of Motor Vehicles concluded that the best
overall crash predictor for both concurrent and nonconcurrent events is
the number of single convictions. This study used 3 consecutive years
of data, comparing the experiences of drivers in the first 2 years with
their experiences in the final year.
    Applying principles from these studies to the past 3-year record of
the 24 applicants, two of the applicants had a traffic violation for
speeding, two of the applicants had a traffic violation for failure to
obey a traffic sign, two of the applicants had a traffic violation for
driving in the wrong lane, one of the applicants had a traffic
violation for unsafe operation of a motor vehicle, and three applicants
were involved in a crash. The applicants achieved this record of safety
while driving with their vision impairment, demonstrating the
likelihood that they have adapted their driving skills to accommodate
their condition. As the applicants' ample driving histories with their
vision deficiencies are good predictors of future performance, FMCSA
concludes their ability to drive safely can be projected into the
future.
    We believe that the applicants' intrastate driving experience and
history provide an adequate basis for predicting their ability to drive
safely in interstate commerce. Intrastate driving, like interstate
operations, involves substantial driving on highways on the interstate
system and on other roads built to interstate standards. Moreover,
driving in congested urban areas exposes the driver to more pedestrian
and vehicular traffic than exists on interstate highways. Faster
reaction to traffic and traffic signals is generally required because
distances between them are more compact. These conditions tax visual
capacity and driver response just as intensely as interstate driving
conditions. The veteran drivers in this proceeding have operated CMVs
safely under those conditions for at least 3 years, most for much
longer. Their experience and driving records lead us to believe that
each applicant is capable of operating in interstate commerce as safely
as he/she has been performing in intrastate commerce. Consequently,
FMCSA finds that exempting these applicants from the vision standard in
49 CFR 391.41(b)(10) is likely to achieve a level of safety equal to
that existing without the exemption. For this reason, the Agency is
granting the exemptions for the 2-year period allowed by 49 U.S.C.
31136(e) and 31315 to the 24 applicants listed in the notice of
December 11, 2009 (74 FR 65842).
    We recognize that the vision of an applicant may change and affect
his/her ability to operate a CMV as safely as in the past. As a
condition of the exemption, therefore, FMCSA will impose requirements
on the 24

individuals consistent with the grandfathering provisions applied to
drivers who participated in the Agency's vision waiver program.
    Those requirements are found at 49 CFR 391.64(b) and include the
following: (1) That each individual be physically examined every year
(a) by an ophthalmologist or optometrist who attests that the vision in
the better eye continues to meet the standard in 49 CFR 391.41(b)(10),
and (b) by a medical examiner who attests that the individual is
otherwise physically qualified under 49 CFR 391.41; (2) that each
individual provide a copy of the ophthalmologist's or optometrist's
report to the medical examiner at the time of the annual medical
examination; and (3) that each individual provide a copy of the annual
medical certification to the employer for retention in the driver's
qualification file, or keep a copy in his/her driver's qualification
file if he/she is self-employed. The driver must also have a copy of
the certification when driving, for presentation to a duly authorized
Federal, State, or local enforcement official.

Discussion of Comments

    FMCSA received no comments in this proceeding.

Conclusion

    Based upon its evaluation of the 24 exemption applications, FMCSA
exempts, Dennis J. Ameling, Cris D. Bush, Cary Carn, Billy C. Chenault,
Matthew J. Cruver, Harvey H. Curtis, Sr., David E. Evans, Wayne W.
Ferguson, Randy M. Garcia, Miguel Godinez, Henry J. Gregoire, Jr.,
Jason L. Hoovan, Tom A. McCarty, Carlos C. Mendez-Castellon, Glenn A.
Miller, Raymond R. Miller, Russell L. Moyers, William E. Norris, Donald
D. Overton, Willie L. Parks, Derrick A. Robinson, Clarence Robinshaw,
Jr., Norman J. Watson and Jeffrey T. Zuniga from the vision requirement
in 49 CFR 391.41(b)(10), subject to the requirements cited above (49
CFR 391.64(b)).
    In accordance with 49 U.S.C. 31136(e) and 31315, each exemption
will be valid for 2 years unless revoked earlier by FMCSA. The
exemption will be revoked if: (1) The person fails to comply with the
terms and conditions of the exemption; (2) the exemption has resulted
in a lower level of safety than was maintained before it was granted;
or (3) continuation of the exemption would not be consistent with the
goals and objectives of 49 U.S.C. 31136 and 31315.
    If the exemption is still effective at the end of the 2-year
period, the person may apply to FMCSA for a renewal under procedures in
effect at that time.

    Issued on February 19, 2010.
Larry W. Minor,
Associate Administrator for Policy and Program Development.
[FR Doc. 2010-4255 Filed 3-1-10; 8:45 am]
BILLING CODE 4910-EX-P