Notice of Inquiry

Federal Register / Vol. 84, No. 60 / Thursday, March 28, 2019 / Notices
can be found at: http://www.ferc.gov/
docs-filing/efiling/filing-req.pdf. For
other information, call (866) 208–3676
(toll free). For TTY, call (202) 502–8659.
Dated: March 21, 2019.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
[FR Doc. 2019–05897 Filed 3–27–19; 8:45 am]
BILLING CODE 6717–01–P

DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
[Docket No. PL19–3–000]

Inquiry Regarding the Commission’s
Electric Transmission Incentives
Policy
Federal Energy Regulatory
Commission.
ACTION: Notice of inquiry.
AGENCY:

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:
SUMMARY:

11759

David Tobenkin (Technical
Information), Office of Energy Policy
and Innovation, Federal Energy
Regulatory Commission, 888 First
Street NE, Washington, DC 20426,
(202) 502–6445, david.tobenkin@
ferc.gov.
Adam Batenhorst (Legal Information),
Office of the General Counsel, Federal
Energy Regulatory Commission, 888
First Street NE, Washington, DC
20426, (202) 502–6150,
adam.batenhorst@ferc.gov.
Adam Pollock (Technical Information),
Office of Energy Market Regulation,
Federal Energy Regulatory
Commission, 888 First Street NE,
Washington, DC 20426, (202) 502–
8458, adam.pollock@ferc.gov.
SUPPLEMENTARY INFORMATION:

Table of Contents
Paragraph
Nos.

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I. Background ......................................................................................................................................................................................
A. FPA Section 219 .....................................................................................................................................................................
B. Order Nos. 679 and 679–A ....................................................................................................................................................
C. 2012 Policy Statement ............................................................................................................................................................
D. Order No. 1000 .......................................................................................................................................................................
II. Subject of the Notice of Inquiry ....................................................................................................................................................
A. Approach to Incentive Policy ................................................................................................................................................
1. Incentives Based on Project Risks and Challenges ........................................................................................................
2. Incentives Based on Expected Project Benefits ..............................................................................................................
3. Incentives Based on Project Characteristics ...................................................................................................................
B. Incentive Objectives ...............................................................................................................................................................
1. Reliability Benefits ...........................................................................................................................................................
2. Economic Efficiency Benefits ..........................................................................................................................................
3. Persistent Geographic Needs ...........................................................................................................................................
4. Flexible Transmission System Operation .......................................................................................................................
5. Security .............................................................................................................................................................................
6. Resilience .........................................................................................................................................................................
7. Improving Existing Transmission Facilities ...................................................................................................................
8. Interregional Transmission Projects ................................................................................................................................
9. Unlocking Locationally Constrained Resources .............................................................................................................
10. Ownership by Non-Public Utilities ..............................................................................................................................
11. Order No. 1000 Transmission Projects .........................................................................................................................
12. Transmission Projects in Non-RTO/ISO Regions .........................................................................................................
C. Existing Incentives ..................................................................................................................................................................
1. ROE-Adder Incentives .....................................................................................................................................................
2. Non-ROE Transmission Incentives .................................................................................................................................
D. Mechanics and Implementation ............................................................................................................................................
1. Duration of Incentives .....................................................................................................................................................
2. Case-by-Case vs. Automatic Approach in Reviewing Incentive Applications .............................................................
3. Interaction Between Different Potential Incentives in Determining Correct Level of ROE Incentives ......................
4. Bounds on ROE Incentives ..............................................................................................................................................
E. Metrics for Evaluating the Effectiveness of Incentives .........................................................................................................
III. Comment Procedures ....................................................................................................................................................................
IV. Document Availability .................................................................................................................................................................

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

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2005),1 codified as section 219 of the
Federal Power Act (FPA),2 which
directed the Commission to use
transmission incentives to help ensure
1 Energy

Policy Act of 2005, Public Law 109–58,
sec. 1261 et seq., 119 Stat. 594 (2005).
2 16 U.S.C. 824s.

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reliability and reduce the cost of
delivered power by reducing
transmission congestion.3 In 2006, the
3 The Commission is generally reevaluating its
ROE policy in a separate Notice of Inquiry issued
concurrently with this notice. Inquiry Regarding the

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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.
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.
I. Background
A. FPA Section 219

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3. Prior to 2005, the Commission
considered requests for certain
transmission incentives pursuant to
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).
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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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:
• 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
• provide a return on equity that
attracts new investment in transmission
facilities, including related transmission
technologies; 11
• 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
• 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
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
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).
10 16 U.S.C. 824s(b)(1).
11 Id. 824s(b)(2).
12 Id. 824s(b)(3).
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.
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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charged by such utility or through the
transmission rates charged by the
Transmission Organization that
provides transmission service to such
utility.
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
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);
16 Order
17 Id.

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• hypothetical capital structures;
• accelerated depreciation for rate
recovery; and
• recovery of prudently incurred precommercial 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.
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
10. The Commission provided several
examples of categories of transmission
projects that might satisfy the abovenoted ‘‘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 locationconstrained 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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18 Order

No. 679–A, 117 FERC ¶ 61,345.
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.
21 Id. P 21. The Commission noted these examples
of types of transmission projects that might qualify
19 The

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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
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
for an ROE adder for risks and challenges was not
an exhaustive list. Id. P 22.
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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11761

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.
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?
24 See

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(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?

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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
(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 performancebased ratemaking and to ensure that
incentive-based rates are just and
reasonable,26 Congress did not require
the Commission to base an incentive
25 Potential examples of these benefits and their
potential relationship to types of transmission
projects are described below in Section II.B.1–2.
26 16 U.S.C. 824s(a), (d).

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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.
(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-tocost 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
(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
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.
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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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
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,
29 16
30 Id.

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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

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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.
(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
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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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.
(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 cybersecurity 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
32 See W. Grid Dev., LLC, 130 FERC ¶ 61,056, at
PP 2, 43–46, order denying reh’g, 133 FERC
¶ 61,029 (2010).
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

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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.
(Q 34) Should transmission projects
that enhance resilience be eligible for
incentives based upon their reliabilityenhancing 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?

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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
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).
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).
35 16 U.S.C. 824s(b)(3).

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utilization of existing transmission
system assets.
(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

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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.
(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
(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
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.
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%20
Web%20Overview272899.pdf.

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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 nonpublic utilities and, if so, how?

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11. Order No. 1000 Transmission
Projects
33. The Commission has considered
whether it could reduce transmission
developer risk by granting blanket preapproval (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
(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 nonincumbent 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
(Q 54) Should the Commission
continue to use certain incentives to
seek to place non-incumbent
39 See Notice Inviting Post-Technical Conference
Comments, Docket No. AD16–18–000, at 2 (Aug. 3,
2016).
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).

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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

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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’ forprofit 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 nondiscriminatory 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
(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
(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
41 Order

No. 679, 116 FERC ¶ 61,057 P 224.
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).
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).
45 Order No. 679, 116 FERC ¶ 61,057 at P 326.
42 Id.

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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
(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?
(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?
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

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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).
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.
49 Order No. 679, 116 FERC ¶ 61,057 at P 331.

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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.
(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 precommercial costs as an expense or as a
regulatory asset—reduce the financial
and regulatory risks associated with
transmission investment.51
(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
50 2012 Incentives Policy Statement, 141 FERC
¶ 61,129 at P 21 & nn.27–28.
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.

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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.
(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
52 Order

No. 679, 116 FERC ¶ 61,057 at PP 123,

131.

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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
(Q 77) Should the Commission grant
the abandoned plant incentive
automatically, rather than on a case-bycase 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?

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

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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
(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
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
56 Order

No. 679–A, 117 FERC ¶ 61,345 at P 21.
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.
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 HydroElec. Co., 165 FERC ¶ 61,030 (2018); Ass’n of
Businesses Advocating Tariff Equity v.
Midcontinent Indep. Sys. Operator, Inc., 165 FERC
¶ 61,118 (2018).
57 An

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Federal Register / Vol. 84, No. 60 / Thursday, March 28, 2019 / Notices

(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.
(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
59 Cal.

Pub. Util. Comm’n v. FERC, 879 F.3d at

amozie on DSK9F9SC42PROD with NOTICES

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 highlevel 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).

VerDate Sep<11>2014

18:57 Mar 27, 2019

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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

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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 202–
502–6652 (toll free at 1–866–208–3676)
or email at ferconlinesupport@ferc.gov,
or the Public Reference Room at (202)
502–8371, TTY (202)502–8659. Email
the Public Reference Room at
public.referenceroom@ferc.gov.
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

DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
[Project No. 14861–001]

FFP Project 101, LLC; Notice of Intent
To File License Application, Filing of
Pre-Application Document, and
Approving Use of the Traditional
Licensing Process
a. Type of Filing: Notice of Intent to
File License Application and Request to
Use the Traditional Licensing Process.
b. Project No.: 14861–001.
c. Date Filed: January 28, 2019.
d. Submitted By: Rye Development on
behalf of FFP Project 101, LLC.
e. Name of Project: Goldendale
Pumped Storage Project.
f. Location: Off-stream (north side) of
the Columbia River at River Mile 215.6

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