Document ID: FERC-2019-0352-0001
Agency: ferc
Document Type: Notice
Title: Inquiry Regarding the Commission's Electric Transmission Incentives Policy
Posted Date: 2019-03-28T04:00Z

[Federal Register Volume 84, Number 60 (Thursday, March 28, 2019)]
[Notices]
[Pages 11759-11768]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[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, (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.
 
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

[[Page 11760]]

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);

[[Page 11761]]

     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?

[[Page 11762]]

    (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,

[[Page 11763]]

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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[[Page 11764]]

    (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.
---------------------------------------------------------------------------

    \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

[[Page 11765]]

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).
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    (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

[[Page 11766]]

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\
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    \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.
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    (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\
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    \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

[[Page 11767]]

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\
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    \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\
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    \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

[[Page 11768]]

(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).
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    (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 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