166 FERC ¶ 61,208

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

[Docket No. PL19-3-000]

Inquiry Regarding the Commission’s Electric Transmission Incentives Policy

(March 21, 2019)

AGENCY: Federal Energy Regulatory Commission.

ACTION: Notice of Inquiry.

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 [INSERT DATE 90 DAYS AFTER DATE OF

PUBLICATION IN THE FEDERAL REGISTER], and Reply Comments are due

[INSERT DATE 120 DAYS AFTER DATE OF PUBLICATION IN THE 

FEDERAL REGISTER]. 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.
Docket No. PL19

-3-000 ii

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
166 FERC ¶ 61,208

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Inquiry Regarding the Commission’s Electric 

Transmission Incentives Policy

 Docket No. PL19-3-000

NOTICE OF INQUIRY

(March 21, 2019)

TABLE OF CONTENTS

Paragraph Numbers

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 Challenges............................................. 15.

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.
Docket No. PL19-3-000 - 2 -

2. Non-ROE Transmission Incentives..................................................................... 40.

D. Mechanics and Implementation .............................................................................. 44.

1. Duration of Incentives......................................................................................... 44.

2. Case-by-Case vs. Automatic Approach in Reviewing Incentive Applications... 45.

3. Interaction Between Different Potential Incentives in Determining Correct Level 

of ROE Incentives.................................................................................................... 46.

4. Bounds on ROE Incentives.................................................................................. 47.

E. Metrics for Evaluating the Effectiveness of Incentives........................................... 48.

III. Comment Procedures.................................................................................................. 49.

IV. Document Availability ............................................................................................... 53.

1. In this Notice of Inquiry, the Commission seeks comment on the scope and 

implementation of its electric transmission incentives regulations and policy pursuant to 

section 1241 of the Energy Policy Act of 2005 (EPAct 2005),1 codified as section 219 of 

the Federal Power Act (FPA),2 which directed the Commission to use transmission 

incentives to help ensure reliability and reduce the cost of delivered power by reducing 

transmission congestion.3

 In 2006, the Commission implemented section 1241 by 

issuing Order No. 679,4 which established the Commission’s basic approach to 

 1 Energy Policy Act of 2005, Pub. L. No. 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).
Docket No. PL19-3-000 - 3 -

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 future6 requests for transmission incentives in a 

manner consistent with Congress’s direction in section 219. Accordingly, through this 

 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.
Docket No. PL19-3-000 - 4 -

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 

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: 

• 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

 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, Pub. L. No. 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).
Docket No. PL19-3-000 - 5 -

• 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 Organization15 and ensure that any costs recoverable pursuant to this 

subsection may be recovered by such utility through the transmission rates charged by 

 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 C.F.R. 35.35(b)(2).
Docket No. PL19-3-000 - 6 -

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 

 16 Order No. 679, 116 FERC ¶ 61,057 at PP 22, 24.

17 Id. PP 23, 60.
Docket No. PL19-3-000 - 7 -

7. The Commission also described a variety of incentives that would potentially be 

available, including: 

• adders to a base ROE: (1) to compensate for the risks and challenges of a 

specific transmission project (ROE adder for risks and challenges); (2) for 

forming a transmission-only company (Transco adder); (3) for joining a 

regional transmission organization (RTO) or independent system operator 

(ISO) (RTO/ISO adder); or (4) for use of an advanced transmission technology 

(technology adder); 

• recovery of 100 percent of prudently incurred costs of transmission facilities 

that are cancelled or abandoned due to factors that are beyond the control of 

the public utility (abandoned plant incentive); 

• inclusion of 100 percent of construction work in progress (CWIP) in rate base 

(CWIP incentive);

• hypothetical capital structures; 

• accelerated depreciation for rate recovery; and 

• recovery of prudently incurred pre-commercial operations costs as an expense 

or through a regulatory asset (regulatory asset incentive). 

8. On December 22, 2006, in Order No. 679-A, the Commission granted rehearing in 

part and denied rehearing in part of Order No. 679.18 The Commission largely affirmed 

 18 Order No. 679-A, 117 FERC ¶ 61,345.
Docket No. PL19-3-000 - 8 -

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

 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.
Docket No. PL19-3-000 - 9 -

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

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 

 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.

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).
Docket No. PL19-3-000 - 10 -

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 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 

 23 See Order No. 1000, 136 FERC ¶ 61,051 at PP 4-6, 8.
Docket No. PL19-3-000 - 11 -

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.

 24 See Order No. 679, 116 FERC ¶ 61,057 at PP 26.
Docket No. PL19-3-000 - 12 -

1. Incentives Based on Project Risks and Challenges

15. As noted, the Commission in Order No. 679 established a requirement that each 

applicant must demonstrate that there is a nexus between the incentive sought and the 

risks and challenges of investment being made. Although the 2012 Incentives Policy 

Statement reframed this standard, it remains central to the Commission’s approach in 

evaluating incentive applications.

Q 1) Should the Commission retain the risks and challenges 

framework for evaluating incentive applications?

Q 2) Is providing incentives to address risks and challenges an

appropriate proxy for the expected benefits brought by 

transmission and identified in section 219 (i.e., ensuring reliability 

or reducing the cost of delivered power by reducing transmission 

congestion)? If risks and challenges are not a useful proxy for 

benefits, is it an appropriate approach for other reasons? 

Q 3) The Commission currently considers risks both in calculating 

a public utility’s base ROE and in assessing the availability and 

level of any ROE adder for risks and challenges. Is this approach 

still appropriate? If so, which risks are relevant to each inquiry, 

and, if they differ, how should the Commission distinguish 

between risks and challenges examined in each inquiry?
Docket No. PL19-3-000 - 13 -

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?

 25 Potential examples of these benefits and their potential relationship to types of 

transmission projects are described below in Section II.B.1-2.
Docket No. PL19-3-000 - 14 -

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.

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 benefitto-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? 

 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.
Docket No. PL19-3-000 - 15 -

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 there drawbacks 

to this approach, particularly relative to the current risks and 

 28 Potential examples of these characteristics and their potential relationship to 

types of transmission projects are described below in Section II.B.3-12.
Docket No. PL19-3-000 - 16 -

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 

 29 16 U.S.C. 824s(a).
Docket No. PL19-3-000 - 17 -

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 utilizes 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, 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.

 30 Id. 824s(b)-(c).
Docket No. PL19-3-000 - 18 -

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 
Docket No. PL19-3-000 - 19 -

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. 

 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.
Docket No. PL19-3-000 - 20 -

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 
Docket No. PL19-3-000 - 21 -

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. 

 32 See W. Grid Dev., LLC, 130 FERC ¶ 61,056, at PP 2, 43-46, order denying 

reh’g, 133 FERC ¶ 61,029 (2010).
Docket No. PL19-3-000 - 22 -

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

Q 32) Should the Commission incentivize physical and cybersecurity enhancements at transmission facilities? If so, what types 

of security investments should qualify for transmission incentives? 

What type of incentive(s) would be appropriate? 

 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).
Docket No. PL19-3-000 - 23 -

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 reliability-enhancing 

attributes?

Q 35) If so, how could the Commission consider or measure the 

benefits of an individual project towards grid resilience? 

 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).
Docket No. PL19-3-000 - 24 -

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.

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 maintenancerelated expenses that a transmission owner would make in its 

ordinary course of business?

 35 16 U.S.C. 824s(b)(3).
Docket No. PL19-3-000 - 25 -

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 standalone 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?
Docket No. PL19-3-000 - 26 -

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 project36 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?

 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.
Docket No. PL19-3-000 - 27 -

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? 

 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.
Docket No. PL19-3-000 - 28 -

Q 48) If so, what metrics could the Commission consider when 

evaluating whether a transmission project facilitates the 

interconnection of generation? 

Q 49) Should such an incentive focus on resources already in the 

queue, a region’s potential for new resources, or some other 

measure? How could the Commission evaluate the potential for 

further resource development in a particular geographic area?

10. Ownership by Non-Public Utilities

32. Section 219(b)(1) encourages the Commission to facilitate capital investment in 

transmission infrastructure, regardless of the ownership of those facilities. 

Q 50) Are there barriers to non-public utilities’ ownership of 

transmission facilities?

Q 51) Should the Commission consider granting incentives to 

promote joint ownership arrangements with non-public utilities 

and, if so, how?

11. Order No. 1000 Transmission Projects 

33. The Commission has considered whether it could reduce transmission developer 

risk by granting blanket pre-approval (i.e., a rebuttable presumption) of three risk-
Docket No. PL19-3-000 - 29 -

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 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

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 

 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).
Docket No. PL19-3-000 - 30 -

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 nonRTO/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.
Docket No. PL19-3-000 - 31 -

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 

 41 Order No. 679, 116 FERC ¶ 61,057 P 224.

42 Id. PP 224-227.
Docket No. PL19-3-000 - 32 -

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-byproject basis?

Q 60) Should the Transco incentive exclude assets that a Transco 

buys, rather than develops? 

 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).
Docket No. PL19-3-000 - 33 -

b. RTO/ISO Participation

38. Section 219(c) requires that the Commission provide incentives to transmitting 

utilities or electric utilities that join an RTO or ISO. In Order No. 679, the Commission 

found that ROE incentives should be granted to utilities that “join and/or continue to be a 

member of an ISO, RTO, or other Commission-approved Transmission Organization.”45 

The Commission declined to make a finding on the appropriate size or duration of the 

incentive.

46 Subsequently, the U.S. Court of Appeals for the Ninth Circuit found that the 

Commission’s granting of an RTO participation incentive to Pacific Gas and Electric Co. 

(PG&E) was arbitrary and capricious in its application of Order Nos. 679 and 679-A 

because the Commission failed to provide a reasoned explanation for granting the 

incentive in light of the Commission’s longstanding policy that incentives should only be 

granted to induce future behavior.

47 

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 

 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).
Docket No. PL19-3-000 - 34 -

automatic provision of CWIP in rate base or the abandoned plant

incentive48 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 projectspecific 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?

 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.
Docket No. PL19-3-000 - 35 -

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. 

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.

 50 2012 Incentives Policy Statement, 141 FERC ¶ 61,129 at P 21 & nn.27-28.
Docket No. PL19-3-000 - 36 -

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

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?

 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.
Docket No. PL19-3-000 - 37 -

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.

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?

 52 Order No. 679, 116 FERC ¶ 61,057 at PP 123, 131.
Docket No. PL19-3-000 - 38 -

Q 73) Have hypothetical capital structures been effective in 

reducing the overall cost of debt by rendering the capital structure 

more predictable?

Q 74) In what circumstances, if any, should hypothetical capital 

structure incentives granted to an entity also be authorized for that 

entity’s yet-to-be formed affiliates?

Q 75) Under what circumstances, if any, should hypothetical capital 

structures extend beyond the construction period?

Q 76) Should the Commission provide a consistent hypothetical 

structure (e.g., 50 percent debt and 50 percent equity)? 

Alternatively, should the Commission cap the equity percentage at 

some upper limit (e.g., 50 percent)? 

c. Recovery of the Cost of Abandoned Plant

42. Even prior to Order No. 679, the Commission granted recovery of 100 percent of 

the prudently incurred costs of transmission facilities that are cancelled or abandoned due 

to factors beyond the control of the public utility (the abandoned plant incentive) as a 

way of mitigating certain risks that are outside the control of the developer.53 Order 

No. 679 stated that transmission developers may be entitled to recover 100 percent of the 

 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)).
Docket No. PL19-3-000 - 39 -

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-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.

 54 Id. P 163.
Docket No. PL19-3-000 - 40 -

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 
Docket No. PL19-3-000 - 41 -

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 

 55 For example, the incentive for joining an RTO/ISO or forming a Transco could 

be limited to a set number of years.
Docket No. PL19-3-000 - 42 -

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 

 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.
Docket No. PL19-3-000 - 43 -

Q 93) Should the Commission establish a more formulaic 

framework for determining the appropriate level and combination 

of incentives? If such a framework is created, what elements 

should it include? 

Q 94) Alternatively, if the Commission continues evaluating 

incentive requests on a case-by-case basis, how could the 

Commission provide more detailed explanations in individual 

cases to better describe how it derives the appropriate level and 

combination of incentives? If so, what elements should such 

explanations provide?

Q 95) The Commission’s current policy is that the total ROE may 

not exceed the zone of reasonableness. If a transmission project 

qualifies for ROE incentives, should there be an upper limit or 

range that the total ROE cannot exceed? If so, what is the 

appropriate limit or range? Should this vary based on how the 

Commission sets base ROE?58 

 58 The Commission has proposed a methodology for base ROE and established a 

paper hearing proceeding on whether and how this methodology should apply. See 

Martha Coakley v. Bangor Hydro-Elec. Co., 165 FERC ¶ 61,030 (2018); Ass’n of 

Businesses Advocating Tariff Equity v. Midcontinent Indep. Sys. Operator, Inc., 165 

FERC ¶ 61,118 (2018).
Docket No. PL19-3-000 - 44 -

4. Bounds on ROE Incentives

47. The benefits of various transmission projects may vary substantially and, in some 

cases, be difficult to compare. Particularly given the current risks and challenges 

framework, the Commission has maintained discretion to determine the level of any 

granted incentive ROE rather than establishing pre-determined levels or ranges for 

incentive ROEs.

Q 96) For ROE incentives, to what extent, if any, should the 

Commission retain discretion to determine the appropriate level of 

ROE incentives? 

Q 97) If the Commission retains discretion with respect to 

determining ROE incentives, should its discretion be bound within 

a pre-determined range (e.g., between 50 and 100 basis points)? If 

so, what is the appropriate range and why?

E. Metrics for Evaluating the Effectiveness of Incentives

48. The Commission has a “longstanding policy that incentives should only be 

awarded to induce voluntary conduct.”59 Nevertheless, it can sometimes be difficult to 

identify the extent to which a particular incentive motivates a transmission developer to 

take a particular action. Order No. 679 adopted an annual reporting requirement, Form 

FERC-730, which requires transmission incentives recipients to provide limited 

 59 Cal. Pub. Util. Comm'n v. FERC, 879 F.3d at 978.
Docket No. PL19-3-000 - 45 -

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?

 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).
Docket No. PL19-3-000 - 46 -

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 
Docket No. PL19-3-000 - 47 -

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 [INSERT 

DATE 90 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL 

REGISTER], and Reply Comments are due [INSERT DATE 120 DAYS AFTER 

DATE OF PUBLICATION IN THE FEDERAL REGISTER]. 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 web site 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 
Docket No. PL19-3-000 - 48 -

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 
Docket No. PL19-3-000 - 49 -

Room at (202) 502-8371, TTY (202)502-8659. E-mail the Public Reference Room at 

public.referenceroom@ferc.gov.

By direction of the Commission.

( S E A L )

Nathaniel J. Davis, Sr.,

Deputy Secretary.