[Federal Register Volume 85, Number 64 (Thursday, April 2, 2020)]
[Proposed Rules]
[Pages 18784-18810]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2020-06321]



[[Page 18783]]

Vol. 85

Thursday,

No. 64

April 2, 2020

Part V





Department of Energy





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Federal Energy Regulatory Commission





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18 CFR Part 35





Electric Transmission Incentives Policy Under Section 219 of the 
Federal Power Act; Proposed Rule

  Federal Register / Vol. 85 , No. 64 / Thursday, April 2, 2020 / 
Proposed Rules  

[[Page 18784]]


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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM20-10-000]


Electric Transmission Incentives Policy Under Section 219 of the 
Federal Power Act

AGENCY: Federal Energy Regulatory Commission, DOE.

ACTION: Notice of proposed rulemaking.

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SUMMARY: The Federal Energy Regulatory Commission proposes to revise 
its existing regulations that implemented section 219 of the Federal 
Power Act in light of the changes in transmission development and 
planning over the last few years.

DATES: Comments are due July 1, 2020.

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, [email protected]
Adam Batenhorst (Legal Information), Office of the General Counsel, 
Federal Energy Regulatory Commission, 888 First Street NE, Washington, 
DC 20426, (202) 502-6150, [email protected]
Adam Pollock (Technical Information), Office of Energy Market 
Regulation, Federal Energy Regulatory Commission, 888 First Street NE, 
Washington, DC 20426, (202) 502-8458, [email protected]

SUPPLEMENTARY INFORMATION: 

Table of Contents

 
                                                          Paragraph Nos.
 
I. Introduction.........................................               1
II. Background..........................................              12
    A. FPA Section 219..................................              12
    B. Order Nos. 679 and 679-A.........................              15
    C. Order No. 1000...................................              18
    D. 2012 Policy Statement............................              20
    E. 2019 Notice of Inquiry...........................              22
    F. Grid-Enhancing Technologies Workshop.............              23
III. Need for Reform....................................              24
IV. Discussion..........................................              34
    A. Shift From Risks and Challenges to Benefits......              34
    B. Incentive ROE Reforms............................              41
        1. ROE Incentives...............................              42
            a. ROE Incentive for Economic Benefits......              42
            b. Adoption of a Benefit-to-Cost Test.......              44
            c. Benefit-to-Cost Measurements.............              48
            d. Establishing a Benefit-to-Cost Threshold               56
             for Economic Incentives....................
        2. Reliability Benefits.........................              63
            a. Reliability Incentive Proposal...........              65
            b. Proposed Showing and Commission Analysis.              74
    C. Ensuring Reasonableness of ROE...................              76
    D. Non-ROE Incentives...............................              82
    E. Incentives Available to Transcos.................              85
        1. Background and Experience to Date............              85
        2. Proposed Revisions to Transco Incentives.....              91
    F. Incentives for RTO Participation.................              92
        1. Background and Experience to Date............              92
        2. RTO-Participation Incentive Proposal.........              97
    G. Incentives for Transmission Technologies.........             100
        1. Background and Experience to Date............             100
        2. Proposed Incentives..........................             101
            a. Transmission Technology Incentive........             105
            b. Deployment Incentive.....................             108
        3. Eligibility and Requirements.................             111
            a. Transmission Technology Statement........             111
            b. Pilot Programs...........................             112
            c. Reporting Requirement....................             113
    H. Disclosure of Anticipated Incentives.............             114
    I. Program Management...............................             115
        1. FERC Form 730................................             115
            a. Form 730 Proposed Format Changes.........             117
        2. Scope of Public Utility Reporting Obligation.             122
        3. Benefits Reporting in Form 730...............             124
V. Information Collection Statement.....................             127
VI. Environmental Analysis..............................             139
VII. Regulatory Flexibility Act.........................             140
VIII. Comment Procedures................................             146
IX. Document Availability...............................             150
 


[[Page 18785]]

I. Introduction

    1. In this notice of proposed rulemaking (NOPR), the Federal Energy 
Regulatory Commission (Commission) proposes to revise its existing 
transmission incentives policy and corresponding regulations 
(Transmission Incentives Regulations) \1\ in light of changes in 
transmission development and planning in the last few years. After the 
enactment of the Energy Policy Act of 2005,\2\ which added section 219 
to the Federal Power Act (FPA),\3\ the Commission promulgated Order No. 
679 \4\ pursuant to FPA section 219.
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    \1\ 18 CFR 35.35.
    \2\ Energy Policy Act of 2005, Public Law 109-58, sec. 1241, 119 
Stat. 594 (2005).
    \3\ 16 U.S.C. 824s.
    \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. After Order No. 679, the Commission last reviewed its 
transmission incentives policy in its 2012 Policy Statement.\5\ Even 
since then, the energy industry has undergone a transformation. The 
landscape for planning, developing, operating, and maintaining 
transmission infrastructure has changed considerably. Those changes 
include an evolution in the resource mix and an increase in the number 
of new resources seeking transmission service, shifts in load patterns, 
the impact of the implementation of the Commission's major rulemaking 
on transmission planning and cost allocation (Order No. 1000),\6\ and 
new challenges to maintaining the reliability of transmission 
infrastructure. As a result of these changes and the Commission's 
greater experience evaluating transmission incentive applications made 
pursuant to Order No. 679 and their relationship to the objectives of 
FPA section 219, we now propose to revise our transmission incentives 
policy to more closely align it with the statutory language of FPA 
section 219.
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    \5\ Promoting Transmission Investment through Pricing Reform, 
141 FERC ] 61,129 (2012) (2012 Policy Statement).
    \6\ 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).
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    3. First, we propose to depart from the risks and challenges 
approach used to evaluate requests for transmission incentives adopted 
in Order No. 679 and instead focus on granting incentives based on the 
benefits to consumers of transmission infrastructure investment 
identified by Congress in FPA section 219: Ensuring reliability and 
reducing the cost of delivered power by reducing transmission 
congestion. As described in the next two paragraphs, a
    4. Second, we propose to offer public utilities an ROE incentive 
for transmission projects that provide sufficient economic benefits, as 
measured by the degree to which such benefits exceed related 
transmission project costs. Specifically, we propose to offer 50 basis 
points of ROE incentives for transmission projects that meet an 
economic benefit-to-cost ratio in the top 75th percentile of 
transmission projects examined over a sample period. We propose to 
offer 50 additional basis points of ROE incentives for transmission 
projects that demonstrate ex-post cost savings that fall in the 90th 
percentile of transmission projects studied over the same sample 
period, as measured at the end of construction.
    5. Third, we propose to offer public utilities an ROE incentive for 
transmission projects that provide significant and demonstrable 
reliability benefits. Specifically, we propose to offer up to 50 basis 
points of ROE incentives for transmission projects that can demonstrate 
potential reliability benefits by providing quantitative analysis, 
where possible, as well as qualitative analysis. Cybersecurity is an 
important part of reliability and we will address cybersecurity 
incentives independently in a separate, future proceeding.
    6. Fourth, we propose to modify the incentive allowing public 
utilities to recover 100 percent of prudently incurred costs of 
transmission facilities that are cancelled or abandoned due to factors 
that are beyond the control of the applicant (Abandoned Plant 
Incentive). Specifically, we propose to allow public utilities with 
transmission projects that are selected in a regional transmission 
planning process for the purposes of cost allocation to recover 100 
percent of abandoned plant costs from the date that such transmission 
projects are selected in a regional transmission planning process for 
the purposes of cost allocation, rather than from the date the 
Commission issues an order granting such recovery.
    7. Fifth, we propose to revise our regulations to eliminate the ROE 
incentive and related acquisition adjustment incentive available to 
stand-alone transmission companies (Transcos).\7\
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    \7\ The Commission defines a Transco as a stand-alone 
transmission company that has been approved by the Commission and 
that sells transmission service at wholesale and/or on an unbundled 
retail basis, regardless of whether it is affiliated with another 
public utility. 18 CFR 35.35(b)(1); Order No. 679, 116 FERC ] 61,057 
at P 201.
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    8. Sixth, consistent with the statutory language in FPA section 
219, we propose to modify the ROE incentive available to transmitting 
utilities or electric utilities that join and/or continue to be a 
member of an Independent System Operator (ISO), Regional Transmission 
Organization (RTO), or other Commission approved Transmission 
Organization \8\ (RTO-Participation Incentive) so that it is available 
regardless of whether the transmitting utility's or electric utility's 
participation in the ISO, RTO, or Transmission Organization is 
voluntary. The proposed RTO-Participation Incentive will be a uniform 
100-basis-point increase to ROE for transmitting utilities that turn 
over their wholesale facilities to the Transmission Organization.
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    \8\ A Transmission Organization is defined as an RTO, ISO, 
independent transmission provider, or other organization finally 
approved by the Commission for the operation of transmission 
facilities. 16 U.S.C. 796(29); 18 CFR 35.35(b)(2). The Commission is 
proposing to move the definition of Transmission Organization from 
Sec.  35.35(b)(2) of its regulations to Sec.  35.35(f) of the 
revised Transmission Incentives Regulations.
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    9. Seventh, we propose to offer public utilities incentives for 
transmission technologies that, as deployed in certain circumstances, 
enhance reliability, efficiency, and capacity, and improve the 
operation of new or existing transmission facilities. We propose that 
these technologies will be eligible for both: (1) A stand-alone, 100-
basis-point ROE incentive on the costs of the specified transmission 
technology project; and (2) specialized regulatory asset treatment. 
Further, we propose to give pilot programs a rebuttable presumption of 
eligibility for these incentives.
    10. Eighth, we propose to establish a 250-basis-point cap on total 
ROE incentives granted to a public utility in place of the current 
policy of limiting ROE incentives to the public utility's zone of 
reasonableness.
    11. Ninth, we propose to reform the information collected from 
transmission incentive applicants in FERC-730, Report of Transmission 
Investment Activity (Form 730), by obtaining this information on a 
project-by-project basis and to expand some of the information 
collected.\9\ We also propose to update the data reporting process.
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    \9\ Concurrent with this NOPR, the Commission is issuing an 
instant final rule clarifying the filing instructions for the 
current Form 730 at the request of the Office of Management and 
Budget (OMB). Reporting of Transmission Investments, Order No. 869, 
170 FERC ] 61,219 (2020). Those changes are reflected into the Form 
730 as proposed in this NOPR.

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[[Page 18786]]

II. Background

A. FPA Section 219

    12. Prior to 2005, the Commission considered requests for certain 
transmission incentives pursuant to FPA section 205.\10\ In 2005, 
Congress amended the FPA to, as relevant here, add a new section 
219.\11\ FPA section 219(a) directed the Commission to promulgate a 
rule providing incentive-based rates for electric transmission for the 
purpose of benefitting consumers by ensuring reliability and reducing 
the cost of delivered power by reducing transmission congestion. FPA 
section 219(b) included a number of specific directives in the required 
rulemaking, including that the rule shall:
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    \10\ 16 U.S.C. 824d; see also Me. Pub. Utils. Comm'n v. FERC, 
454 F.3d 278, 287 (D.C. Cir. 2006).
    \11\ Energy Policy Act of 2005, Pub. L. 109-58, sec. 1241.
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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; \12\
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    \12\ 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; 
\13\
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    \13\ Id. at 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; 
\14\ and
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    \14\ Id. at 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 FPA section 215,\15\ and all prudently incurred costs 
related to transmission infrastructure development pursuant to FPA 
section 216.\16\
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    \15\ FPA section 215 addresses the Commission's role in ensuring 
electric reliability of the bulk power system. Id. at 824o.
    \16\ Id. at 824s(b)(4). FPA section 216 addresses designation of 
and siting of transmission facilities within National Interest 
Electric Transmission Corridors. Id. at 824p.
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    13. FPA section 219(c) states 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 and ensure that any costs recoverable pursuant to this 
subsection may be recovered by such transmitting utility or electric 
utility through the transmission rates charged by such transmitting 
utility or electric utility or through the transmission rates charged 
by the Transmission Organization that provides transmission service to 
such transmitting utility or electric utility.\17\
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    \17\ Id. at 824s(c).
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    14. Finally, FPA section 219(d) provides that rates approved 
pursuant to a rulemaking adopted pursuant to section 219 are subject to 
the requirements in FPA sections 205 and 206 \18\ that all rates, 
charges, terms, and conditions be just and reasonable and not unduly 
discriminatory or preferential.
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    \18\ Id. at 824e.
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B. Order Nos. 679 and 679-A

    15. On July 20, 2006, the Commission issued Order No. 679, adding 
Sec.  35.35 to the Commission's regulations to implement transmission 
incentives, and thereby fulfilling the rulemaking requirement in FPA 
section 219(a). The Commission explained that, to receive an incentive, 
an applicant must satisfy the statutory threshold set forth in FPA 
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 it would apply the FPA section 219(a) 
threshold and the nexus test on a case-by-case basis.\19\
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    \19\ Order No. 679, 116 FERC ] 61,057 at PP 22, 24.
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    16. The Commission also described a variety of incentives that 
would potentially be available, including:
     Increases above the base ROE: (1) To compensate for the 
risks and challenges of a specific transmission project (ROE incentive 
for risks and challenges); (2) for forming a Transco (Transco ROE 
Incentive); (3) for joining a RTO or ISO (RTO-Participation Incentive); 
or (4) for use of an advanced transmission technology;
     The Abandoned Plant Incentive, which is, as explained 
above, the ability to request 100 percent of prudently incurred costs 
associated with abandoned transmission projects to be included in 
transmission rates if such abandonment is outside the applicant's 
control;
     Inclusion of 100 percent of construction work in progress 
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).
    17. On December 22, 2006, in Order No. 679-A, the Commission 
granted rehearing in part and denied rehearing in part of Order No. 
679.\20\ The Commission largely affirmed the conclusions discussed in 
the previous paragraphs while refining certain other aspects of Order 
No. 679. In its subsequent discussion of the nexus test, the Commission 
reaffirmed 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.'' \21\
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    \20\ Order No. 679-A, 117 FERC ] 61,345 at P 1.
    \21\ Id. PP 23, 60.
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C. Order No. 1000

    18. 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 local and regional transmission planning 
processes must provide an opportunity to identify and evaluate 
transmission needs driven by public policy requirements established by 
state or federal laws or regulations; (3) improved coordination between 
neighboring transmission planning regions for new interregional 
transmission facilities; and (4) the removal from Commission-approved 
tariffs and agreements of a federal right of first refusal.\23\
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    \22\ Order No. 1000, 136 FERC ] 61,051.
    \23\ See Order No. 1000-A, 139 FERC ] 61,132 at P 1.
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    19. Order No. 1000 also requires that each public utility 
transmission provider must participate in a regional transmission 
planning process that has: (1) A regional cost allocation method for 
the cost of new transmission facilities selected in a regional 
transmission plan for purposes of cost allocation; and (2) an 
interregional cost allocation method for the cost of new transmission 
facilities that are located in two neighboring transmission planning 
regions and are jointly evaluated by the two regions in the 
interregional transmission coordination process.\24\

[[Page 18787]]

Although Order No. 1000 does not directly address the Commission's 
obligations under FPA section 219, the aforementioned reforms have had 
certain implications for how regional transmission facilities are 
planned and developed.
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    \24\ Order No. 1000, 136 FERC ] 61,051 at P 9.
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D. 2012 Policy Statement

    20. On November 15, 2012, the Commission issued a policy statement 
to provide additional guidance regarding its evaluation of applications 
for transmission incentives under FPA section 219 and Order No. 679. In 
particular, the Commission reframed the nexus test for applicants 
seeking the ROE incentive for risks and challenges and eliminated the 
stand-alone advanced transmission technology incentive.\25\ The 
Commission stated that it would expect an applicant seeking an ROE 
incentive 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 non-ROE 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.\26\
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    \25\ 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 Policy Statement, 141 FERC ] 61,129 at P 23.
    \26\ Id. PP 20-28.
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    21. 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.\27\
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    \27\ 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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E. 2019 Notice of Inquiry

    22. On March 21, 2019, the Commission issued a Notice of Inquiry 
seeking comment on the scope and implementation of its electric 
transmission incentives regulations and policy.\28\ The 2019 Notice of 
Inquiry presented numerous questions regarding the Commission's 
approach to, and objectives of, its incentives policy; the mechanics 
and implementation of an incentives policy; and metrics for evaluating 
the effectiveness of incentives. The Commission received 67 initial 
comments and 47 reply comments.
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    \28\ Inquiry Regarding the Commission's Electric Transmission 
Incentives Policy, 84 FR 11759 (Mar. 28, 2019), 166 FERC 61,208 
(2019) (2019 Notice of Inquiry).
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F. Grid-Enhancing Technologies Workshop

    23. On November 5 and 6, 2019, Commission staff led a workshop on 
grid-enhancing technologies (Grid-Enhancing Technologies Workshop).\29\ 
Grid-Enhancing Technologies Workshop speakers identified several grid-
enhancing technologies, including power flow control, transmission 
topology optimization, advanced line rating management, and storage as 
transmission. Speakers also discussed several methods to incentivize 
the deployment and implementation of grid-enhancing technologies, 
including a shared-savings approach. The Commission also issued a post-
workshop notice seeking comment and received 19 comments.
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    \29\ FERC, Grid-Enhancing Technologies, Notice of Workshop, 
Docket No. AD19-19-000 (Sept. 9, 2019).
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III. Need for Reform

    24. The reforms proposed to the Commission's transmission 
incentives policy will both help to reflect recent changes in the 
industry and transmission planning and more closely align with the 
statutory language of FPA section 219.
    25. As part of ensuring that we continue to meet our statutory 
obligations, the Commission periodically reviews its existing policies 
and regulations. The Commission established its transmission incentives 
policy in Order No. 679 and clarified that policy six years later in 
the 2012 Policy Statement. In the nearly eight years since our last 
formal review of the Commission's transmission incentives policy, the 
landscape for planning, developing, operating, and maintaining 
transmission infrastructure has changed considerably. These changes 
include an evolution in the resource mix, an increase in the number of 
new resources seeking transmission service, shifts in load patterns, 
the Commission's implementation of Order No. 1000's reforms, and new 
challenges to maintaining the reliability of transmission 
infrastructure.
    26. While transmission infrastructure development has remained 
generally robust at an aggregate level, the types of transmission 
projects that are needed, and the use of rate treatments to incent 
them, must evolve to reflect the changes in market fundamentals.
    27. First, the nation's resource mix has evolved since the 
Commission's issuance of Order No. 679 in 2006, with rising use of 
natural gas and renewable resources and declining use of coal. In 2006, 
coal, natural gas, and nuclear made up nearly 88 percent of net 
electric generation in the United States, with coal contributing nearly 
50 percent of total generation and natural gas contributing 20 percent 
of total generation, respectively.\30\ By 2018, coal, natural gas, and 
nuclear still accounted for 82 percent of net electric generation; 27 
percent of total generation was from coal and 36 percent from natural 
gas, respectively. Solar and wind increased from a collective one 
percent in 2006 to eight percent in 2018. These shifts create a need 
for more transmission infrastructure to bring generation to load. A 
survey of Edison Electric Institute (EEI) members shows that the need 
to integrate renewables and natural gas is one of the main drivers for 
expansion of the transmission system, as noted by U.S. Energy 
Information Administration (EIA).\31\
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    \30\ In 2006, coal represented 49 percent, natural gas 20 
percent, and nuclear power 19 percent of net electric generation in 
the United States. U.S. Energy Info. Admin., Total Energy Annual 
Energy Review, Electricity Net Generation: Total (All Sectors), at 1 
(January 2020), https://www.eia.gov/totalenergy/data/monthly/pdf/sec7_5.pdf.
    \31\ U.S. Energy Info. Admin., Today in Energy (Feb. 9, 2018), 
https://www.eia.gov/todayinenergy/detail.php?id=34892.
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    28. In addition to the changing mix of resources used to generate 
electricity, more types of resources are now participating in 
Commission-jurisdictional markets. Industry innovation and market 
reforms, demand-side resources, electric storage, distributed energy 
resources, and new technological innovations provide transmission 
operators with new opportunities as well as new challenges. There is a 
need for existing and new transmission facilities to help facilitate 
integration of these resources and a need to incent development and 
enhancement of transmission facilities so that they are effective in 
doing so.
    29. Changes in load patterns are also driving new types of 
transmission investment. Despite low overall demand

[[Page 18788]]

growth, electrification in industries such as transportation, heating, 
and agriculture are expected to contribute to peak load growth, 
requiring additional transmission investment to meet those needs.\32\ 
Other shifts in load patterns are triggering targeted transmission 
investment, such as by Public Service Enterprise Group to meet urban 
area growth in Newark and Jersey City, New Jersey, or by Dominion 
Energy to meet the increased load needs of data centers in northern 
Virginia.\33\ Another example of transmission being built to meet these 
various needs is the Energy Gateway Project, which EIA notes is being 
built to meet new demand patterns and provide greater access to new 
resources.\34\ The Commission's incentives policy must be effective in 
incenting transmission projects that reflect existing, and can adapt 
rapidly to future, shifts in load growth patterns.
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    \32\ See Brattle Group, The Coming Electrification of the North 
American Economy, at 7-12, 16-21 (Feb. 28, 2019), https://wiresgroup.com/wp-content/uploads/2019/03/Electrification_BrattleReport_WIRES_FINAL_03062019.pdf.
    \33\ Edison Electric Institute, Smarter Energy Infrastructure: 
The Critical Role and Value of Electric Transmission, at 7 (Mar. 
2019), https://www.eei.org/issuesandpolicy/transmission/Documents/2018%20Smarter%20Energy%20Infrastructure%20The%20Critical%20Role%20and%20Value%20of%20Electric%20Transmission.pdf.
    \34\ U.S. Energy Information Administration, Today in Energy 
(Feb. 9, 2018), https://www.eia.gov/todayinenergy/detail.php?id=34892.
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    30. Additionally, transmission planning has evolved significantly. 
The 2012 Policy Statement was issued less than one month after 
transmission planning regions submitted their first round of Order No. 
1000 regional compliance filings. All transmission planning regions 
have now conducted at least two iterations of their regional 
transmission planning process, with some having conducted as many as 
seven.\35\ As part of such processes, the six RTOs/ISOs use 
sophisticated software modeling to identify the relative benefits and 
costs of proposed new transmission projects premised upon transmission 
projects' economic benefits. There is now an opportunity for the 
Commission to leverage the RTOs/ISOs' efforts to better target 
incentives at transmission projects that demonstrate sufficient 
economic benefits, as measured by the degree to which such benefits 
exceed related transmission project costs.
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    \35\ See California Independent System Operator, Inc., 
Transmission Planning for a Reliable, Economic and Open Grid, http://www.caiso.com/planning/Pages/TransmissionPlanning/Default.aspx; 
WestConnect, Regional Planning, http://regplanning.westconnect.com/regional_planning.htm.
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    31. FPA section 219(a) requires that the Commission provide 
incentive-based rates for electric transmission for the purpose of 
benefitting consumers by ensuring reliability and reducing the cost of 
delivered power by reducing transmission congestion. While we are 
encouraged by the investment in transmission infrastructure to date, 
our evaluation of the Commission's incentives policy indicates that 
additional reform may be necessary to continue to satisfy our 
obligations under FPA section 219 in this new transmission planning 
landscape.
    32. Further, in reviewing our incentives policy under Order No. 
679, we have determined that our current policy may not fully 
accomplish the purposes of FPA section 219. Congress in FPA section 219 
directed that the Commission shall establish, by rule, incentive-based 
(including performance-based) rate treatments for the transmission of 
electric energy in interstate commerce by public utilities for the 
purpose of benefitting consumers by ensuring reliability and reducing 
the cost of delivered power by reducing transmission congestion.\36\ As 
discussed in more detail in the following section, we are proposing to 
revise our transmission incentives policy in order to more closely 
align with the statutory language and purpose of FPA section 219. By 
ensuring that our incentives policy better aligns with our statutory 
requirements, we aim to set clear expectations for how the Commission 
will analyze future applications for incentives treatment, as well as 
increased transparency for the regulated industry.
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    \36\ 16 U.S.C. 824s(a) (emphasis added).
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    33. This analysis also should increase certainty for developers; 
better align incentives awarded with transmission project benefits and 
costs; increase the precision and transparency with which transmission 
project benefits are considered by the Commission; and increase the 
ability, over time, of the Commission to determine whether incentives 
are effective in spurring development of transmission projects with 
desirable benefits.

IV. Discussion

A. Shift From Risks and Challenges to Benefits

    34. We propose to revise Sec.  35.35 of the Transmission Incentives 
Regulations to incorporate a benefits test to receive transmission 
incentives and to remove the nexus test from Sec.  35.35(c) of the 
currently effective regulations. FPA section 219(a) explicitly 
recognizes the benefits of transmission projects by directing that the 
Commission shall establish, by rule, incentive-based (including 
performance-based) rate treatments for the transmission of electric 
energy in interstate commerce by public utilities for the purpose of 
benefitting consumers by ensuring reliability and reducing the cost of 
delivered power by reducing transmission congestion.\37\
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    \37\ Id.
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    35. Order Nos. 679 and 679-A implemented the provisions of FPA 
section 219 and established a ``nexus test,'' which required that 
applicants demonstrate a connection between the total package of 
incentives sought and the proposed investment, in light of the risks 
and challenges facing a transmission project seeking incentives under 
FPA section 219.\38\ However, FPA section 219 neither includes this 
standard nor requires the Commission to find that the transmission 
project would otherwise not occur without the incentive.\39\ The 
inclusion of this standard has focused applicants and the Commission on 
the risks and challenges of a transmission project rather than the 
purpose and language of FPA section 219, which is to benefit consumers 
by ensuring reliability and reducing the costs of delivered power by 
reducing transmission congestion, and ensuring that rates remain just 
and reasonable.
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    \38\ The applicant must demonstrate that the transmission 
facilities for which it seeks incentives either ensure reliability 
or reduce the cost of delivered power by reducing transmission 
congestion consistent the requirements of section 219, that the 
total package of incentives is tailored to address the risks and 
challenges faced by the applicant in undertaking the project, and 
that the resulting rates are just and reasonable. 18 CFR 35.35(d); 
see also Order No. 679, 116 FERC ] 61,057 at P 76.
    \39\ See Order No. 679, 116 FERC ] 61,057 at P 53 (stating that 
FPA section 219 provides a new directive to the Commission to permit 
greater incentives and does not on its face require an individual 
showing of need by incentive applicants); see also Conn. Dept. of 
Pub. Util. Control v. FERC, 593 F.3d 30, 34 (D.C. Cir. 2010) 
(``nothing in the law or FERC's stated purpose required FERC to 
adduce evidence . . . `that the adder would produce new transmission 
investment'''). When the Commission explained why it was not 
adopting a ``but for'' test in Order No. 679, it noted that the rule 
was ``based on a clear directive from Congress that does not require 
an applicant to show that it would not build the facilities but for 
the incentives.'' Order No. 679, 116 FERC ] 61,057 at P 48.
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    36. Based on experience to date with the application of Order No. 
679, and in recognition of the changing landscape in the energy 
industry, we believe that refocusing our incentives program to more 
closely align with the statutory directive of FPA section 219 will 
allow the Commission to better fulfill its mandate. We therefore 
propose to

[[Page 18789]]

depart from the ``nexus test'' framework of Order No. 679, and instead 
focus our decision to grant incentives on the benefits to consumers of 
transmission infrastructure investment identified by Congress: ensuring 
reliability and reducing the cost of delivered power by reducing 
transmission congestion. Accordingly, we propose to revise Sec.  
35.35(c) of the proposed Transmission Incentives Regulations to remove 
the nexus test and to implement a benefits test.
    37. As described in detail below, with respect to ROE incentives 
based upon transmission projects' economic and reliability benefits, we 
propose separate analyses to implement the revised Sec.  35.35(c) of 
the Transmission Incentives Regulations, wherein an applicant must 
demonstrate that the incentives it seeks meet a specified benefit-to-
costs threshold for an economic benefits showing or provide a 
significant and demonstrable reliability enhancement for a reliability 
benefits showing, with each of these showings determining eligibility 
for distinct ROE incentives. Consistent with Congressional directive in 
FPA section 219(d), all ROE incentives must be just and reasonable.
    38. Although we propose a shift in the Commission's transmission 
incentive analysis to concentrate on the benefits presented by 
transmission investment, we propose to retain non-ROE incentives, 
including the abandoned plant incentive, CWIP Incentive, hypothetical 
capital structure, accelerated depreciation for rate recovery, and 
regulatory asset treatment.\40\ These non-ROE incentives remain vital 
in facilitating the investment in and the development of transmission 
projects as they remove regulatory barriers and other impediments to 
investment. These incentives will continue to remain available to all 
transmission projects that meet the Commission's rebuttable 
presumptions for transmission projects that result from fair and open 
regional transmission planning, receive construction approval from an 
appropriate state commission or state siting authority, or otherwise 
demonstrate that they are needed to ensure reliability or reduce the 
cost of delivered power by reducing transmission congestion.\41\ We 
propose only incremental reforms to some of these non-ROE 
incentives.\42\ We continue to see transmission project-specific ROE 
incentives, for which we will require additional demonstration of 
benefits, as a supplement to these non-ROE incentives, as discussed 
further below.
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    \40\ 2012 Policy Statement, 141 FERC ] 61,129 at PP 11-14.
    \41\ See proposed 18 CFR 35.35(e).
    \42\ See section II.D.
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    39. We do not propose to require applicants for a transmission 
project-specific ROE incentive based upon transmission projects' 
economic or reliability benefits to demonstrate that base ROE or non-
ROE incentives are insufficient to adequately address the needs of 
these transmission projects before seeking an ROE incentive, as is 
currently required for the ROE incentive for risks and challenges, 
which we propose to eliminate as we shift to a benefits-based approach 
for ROE incentives.
    40. Furthermore, we propose no changes to the procedural 
flexibility offered to applicants seeking incentives, including 
applicants' ability to seek expedited declaratory orders on incentive 
proposals before submitting a filing for approval under FPA section 205 
for inclusion of the incentives in rates.

B. Incentive ROE Reforms

    41. FPA section 219 directed the Commission to provide a framework 
for granting incentives based on the benefits to consumers of 
transmission infrastructure investment that ensured reliability and 
reduced the cost of delivered power by reducing transmission 
congestion. We continue to believe that it is necessary to offer 
incentives under FPA section 219 to ensure an ROE that attracts new 
investment in transmission facilities and continues investment in 
beneficial transmission facilities.\43\ Accordingly, we propose to 
offer a series of transmission ROE incentives designed to ensure that 
returns on equity attract investment in transmission infrastructure 
that has high economic benefits to consumers through congestion relief 
or that enhances reliability.
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    \43\ 16 U.S.C. 824s(b)(2).
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1. ROE Incentives
a. ROE Incentive for Economic Benefits
    42. FPA section 219(a) directs the Commission to establish 
incentive-based rate treatments to benefit consumers by reducing the 
cost of delivered power by reducing transmission congestion, section 
219(b)(1) directs the Commission to promote reliable and economically 
efficient transmission, and section 219(b)(2) directs the Commission to 
provide an ROE that attracts new investment in transmission 
facilities.\44\ Accordingly, we propose to revise Sec.  35.35(d) of our 
regulations to allow applicants to seek ROE incentives for transmission 
projects that provide sufficient economic benefits, as measured by the 
degree to which such benefits exceed related transmission project 
costs, as described further below.
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    \44\ Id. at 824s(a)-(b)(2).
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    43. We propose to grant ROE incentives to economic transmission 
projects based on economic benefit-to-cost tests, including a 50-basis-
point ROE incentive for transmission projects that meet an ex-ante 
benefit-to-cost threshold, described below, and 50 additional basis 
points for transmission projects that demonstrate on an ex-post basis 
that they are able to satisfy a higher benefit-to-cost threshold when 
constructed. Regional \45\ or local \46\ transmission projects may be 
eligible for this incentive.
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    \45\ A regional transmission facility is a transmission facility 
located entirely in one region. Order No. 1000, 136 FERC ] 61,051 at 
n. 374.
    \46\ A local transmission facility is a transmission facility 
located solely within a public utility transmission provider's 
retail distribution service territory or footprint that is not 
selected in the regional transmission plan for purposes of cost 
allocation. Id. at P 63.
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b. Adoption of a Benefit-to-Cost Test
    44. We propose to adopt a benefit-to-cost ratio to determine the 
eligibility of economic transmission projects for ROE incentives to 
attract new investment in transmission facilities in order to implement 
our proposed revisions to Sec.  35.35(d) of the revised Transmission 
Incentives Regulations. We believe that this approach is consistent 
with both a benefits-based approach and industry practice, as explained 
in greater detail below. Several RTOs/ISOs request that the Commission 
not impose a benefits-based incentives approach that would duplicate or 
interfere with their transmission planning efforts, cause inefficient 
use of RTO/ISO staff time, or engender contention and potential 
litigation.\47\ With these concerns in mind, we propose an approach to 
economic benefits-based incentives that we believe is relatively 
simple, transparent, and yet is efficient in relying upon RTOs/ISOs' 
analyses of the economic benefits of transmission projects.
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    \47\ California Independent System Operator Corporation 
Comments, Docket No. PL19-3-000, at 10 (filed June 26, 2019); Grid-
Enhancing Technologies Workshop Transcript Day Two, Docket No. AD19-
19-0000, at 286, 288, 296, 316, 325, 327, 334 (filed Jan. 6, 2020).
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    45. In Order No. 679, the Commission stated that it would not 
require applicants for incentive-based rate

[[Page 18790]]

treatments to provide benefit-to-cost analyses.\48\ Explaining why it 
was not requiring such showings, the Commission listed as 
considerations: (1) The Commission's authority to consider non-cost 
factors in awarding incentives; (2) that Congress's enactment of FPA 
section 219 reflected its determination that incentives generally can 
spur transmission investment which will, in turn, provide the benefits 
of a robust transmission system; and (3) the Commission's intent to 
consider the justness and reasonableness of any proposal for incentive 
rate treatment in individual proceedings.\49\
---------------------------------------------------------------------------

    \48\ Order No. 679, 116 FERC ] 61,057 at P 65.
    \49\ Id.
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    46. However, we believe that shifting from a risks and challenges 
based paradigm to a benefits-based paradigm, where incentives reward 
the most beneficial rather than most challenging transmission projects, 
supports using benefit-to-cost ratios to award economic incentives. 
Many transmission planning regions, including RTOs/ISOs, already 
identify beneficial transmission solutions and the heightened benefit-
to-cost ratio thresholds we adopt below will ensure that we are 
providing incentives to highly beneficial transmission projects. 
Specifically, in many RTOs/ISOs, competing economic transmission 
projects are evaluated through a comparison of transmission projects' 
economic benefits with their costs, generating benefit-to-cost ratios 
that evaluate transmission projects by their net benefits.\50\ In 
addition, many applications requesting ROE incentives for risks and 
challenges already include some analysis of benefits and costs.\51\
---------------------------------------------------------------------------

    \50\ See, e.g., MISO, MTEP18 Transmission Expansion Plan, at 100 
(Sep. 18, 2018), https://cdn.misoenergy.org/MTEP18%20Full%20Report264900.pdf (presenting a comparison of 
benefit-to-cost ratios for potential transmission project for MISO's 
Dakotas/Minnesota region); PJM Interconnection, LLC, Transmission 
Expansion Advisory Committee Market Efficiency Update, at 7 (Dec. 3, 
2015), https://www.pjm.com/-/media/committees-groups/committees/teac/20151203/20151203-market-efficiency-update.ashx (describing the 
reliability pricing model benefit component of the benefit/cost 
ratio).
    \51\ For example, New York Independent System Operator, Inc. 
(NYISO) found that the Empire Project proposed by NEET New York is 
expected to result in: (1) Production cost savings on the NYISO 
system of approximately $274 million to $338 million over a 20-year 
period, adjusted on a present value basis to 2017 dollars; and (2) 
demand congestion change savings on the NYISO system of $582 to 
$1.184 billion over a 20-year period, adjusted on a present value 
basis to 2017 dollars. NextEra Energy Transmission N.Y., Inc., 162 
FERC ] 61,196, at P 21 (2018).
---------------------------------------------------------------------------

    47. The widespread use of benefit-to-cost ratios for evaluating 
economic transmission projects in RTO/ISO transmission planning regions 
demonstrates the reasonableness of employing benefit-to-cost ratios to 
determine whether transmission projects merit ROE incentives premised 
upon economic benefits. The use of benefit-to-cost ratios for awarding 
ROE incentives will allow the Commission to set a clear expectation as 
to the level of benefits relative to costs required to receive an ROE 
incentive. We request comment on the merits of the use of benefit-to-
cost ratios to determine eligibility of transmission projects, 
regardless of the type of transmission project, for ROE incentives 
based on their economic benefits.
c. Benefit-to-Cost Measurements
    48. In calculating the economic benefits of a transmission project 
for which a public utility is requesting ROE incentives, we propose to 
limit measurement of economic benefits to adjusted production costs or 
similar measures of congestion reduction or certain other quantifiable 
benefits that are verifiable and not duplicative. With respect to 
transmission projects' economic benefits, transmission planning regions 
typically evaluate the economic efficiency of transmission projects 
through production cost modeling. This analysis seeks to minimize total 
system cost by evaluating the security constrained unit commitment and 
economic dispatch of the system over a given time horizon within a 
transmission planning region. A transmission project, whether regional 
or local, is classified as ``economic'' if it reduces the total system 
cost by an amount that justifies its cost, usually by establishing net 
positive benefits, and sometimes surpassing a defined benefit-to-cost 
threshold. In RTO/ISO regions, all regional transmission projects 
selected in a regional transmission plan for purposes of cost 
allocation, and sometimes other transmission projects premised 
primarily on their economic benefits, are evaluated through production 
cost or similar modeling.\52\ Some of the non-RTO/ISO regions' 
transmission planning processes also include production cost 
modeling.\53\
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    \52\ See, e.g., California Independent System Operator, Inc., 
2018-2019 Transmission Plan, at sec. 4.4 (Mar. 29, 2019); 
Midcontinent Independent System Operator, Inc., MISO Adjusted 
Production Cost Calculation White Paper (Feb. 1, 2019); PJM Manual 
14B, PJM Regional Transmission Planning Process (Aug. 28, 2019); New 
York Independent System Operator, Inc., Manual 35, Economic Planning 
Process Manual-Congestion Assessment and Resource Integration 
Studies, sec. 2.5 (Feb. 2016).
    \53\ See, e.g., Northern Tier Transmission Group, 2018-2019 
Biennial Transmission Plan, at 10 (Dec. 31, 2019); WestConnect 
Business Practice Manual, section 4.2.1.1.
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    49. In addition, many regions supplement adjusted production cost 
models with other economic benefit metrics. MISO, for example, has also 
proposed to examine reliability transmission project costs avoided by 
the construction of an economic transmission project, as well as the 
impacts on congestion of a settlement between MISO and Southwest Power 
Pool, Inc. (SPP),\54\ and already considers the relative degree to 
which an economic transmission project will solve a congestion problem. 
In this example, MISO might choose an economic transmission project 
that completely resolves congestion in a particular location on the 
system over a transmission project with a higher benefit-to-cost ratio 
that relieves only a portion of the congestion.\55\ Similarly, PJM's 
process allows for a holistic assessment of benefits and considers 
factors, such as constructability analysis, effects of transmission 
project combinations, and changes in load energy payments, in its 
overall consideration of transmission projects.\56\ California 
Independent System Operator Corporation (CAISO) assesses on a case-by-
case basis other economic opportunities that are not necessarily driven 
by congestion. Such economic opportunities may include local capacity 
benefits (e.g., reducing the requirement for local generation capacity 
due to limited transmission capacity into an area).\57\ In NYISO, the 
economic transmission planning process uses production cost savings as 
the primary metric in its initial phase; subsequently, NYISO considers 
additional metrics on a case-by-case basis, depending on the most 
useful ones for each economic planning cycle.\58\ Commenters in other

[[Page 18791]]

proceedings have also identified other potential economic benefits.\59\
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    \54\ Midcontinent Indep. Sys. Operator, Inc., Filing, Docket No. 
ER20-857-000, at 4 (Jan. 21, 2020)).
    \55\ See MISO, MTEP 2018: Transmission Expansion Plan, at 100 
(declining to move a transmission solution forward in the study 
cycle because, ``[a]lthough it shows a good benefit-to-cost ratio, 
it leaves a significant amount of the congestion unaddressed and the 
upgrade will most likely not be enough given the future wind 
development in the Dakotas and Minnesota border area'').
    \56\ PJM, Market Efficiency Study Process and RTEP Window 
Project Evaluation Training, at 21 (Oct. 16, 2018); PJM, 2017 
Regional Transmission Expansion Plan: Book 3 Studies and Results, at 
69 (Feb. 28, 2018).
    \57\ Other benefits include renewable integration benefit, 
resource adequacy benefit, and transmission loss benefits. CAISO, 
Transmission Economic Assessment Methodology, sec. 2.5 Additional 
Benefits of Economically Driven Transmission Expansion (Nov. 2, 
2017).
    \58\ These other metrics include: Estimates of reductions in 
losses, locational based marginal pricing load costs, generator 
payments, installed capacity costs, ancillary services costs, 
emission costs, and transmission congestion contract payments. 
NYISO, NYISO Tariffs, NYISO OATT, att. Y Economic Planning Process, 
sec. 31.3.1.3.5 (11.0.0).
    \59\ See Johannes Pfeifenberger and Judy Chang, Comments, Docket 
No. AD16-18-000 (filed Oct. 3, 2016) (attaching multiple reports on 
transmission planning and the benefits of the transmission system).
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    50. While most RTOs/ISOs employ other economic benefit metrics in 
addition to adjusted production cost, we propose to limit our analysis 
of economic benefits to adjusted production cost, similar measures of 
congestion reduction, and certain other quantifiable benefits that are 
verifiable and not duplicative.\60\ Although excluding factors beyond 
adjusted production cost or similar measures of congestion reduction 
and quantifiable economic benefits will reduce the comprehensiveness of 
the measurement of economic benefits, we believe that this is a 
reasonable tradeoff in the interest of an economic benefits test that 
is transparent and relatively straightforward for applicants to prepare 
and for the Commission to analyze. We also propose to provide a 
rebuttable presumption that economic benefits measured in benefit-to-
cost ratios derived by RTOs/ISOs for transmission projects within their 
footprints should be included in the determination of an applicant's 
transmission project's benefits. Additionally, we propose that the 
appropriate benefit-to-cost ratio for purposes of the ex-ante 
evaluation is measured at the time the RTO/ISO finalizes its analysis 
of potential economic transmission projects within its region.
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    \60\ These might include (but are not limited to): Types of load 
cost savings, capacity benefits, and avoided local transmission 
project costs.
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    51. Although we believe that the use of adjusted production cost, 
similar congestion reduction measurements, and other quantifiable 
benefits strikes a reasonable balance for the purpose analyzing 
economic benefits, we request comment on whether additional types of 
economic benefit measures should be considered for purposes of an 
economic benefit ROE incentive. We also request comment on existing 
methods that are equivalent (or comparable) to adjusted production cost 
that might inform the range of benefits measures that could be 
utilized.
    52. Although some RTOs/ISOs appear to provide stakeholders access 
to the results of their adjusted production cost models, it is unclear 
whether all RTOs/ISOs provide public utilities with the results of 
their adjusted production cost models, similar congestion reduction 
measurements, or other quantifiable benefits as economic benefits 
measures, and the resulting benefit-to-cost ratios in a manner that 
would allow the developer to use these results to seek an ROE incentive 
for economic benefits. For example, some RTOs/ISOs may require 
stakeholders to execute a non-disclosure agreement to gain access to 
study results. In addition, some RTOs/ISOs conduct multiple economic 
simulations for transmission projects, and it is not clear if these 
regions perform a single, final adjusted production cost or equivalent 
economic analysis that would allow for apples-to-apples comparisons of 
transmission projects. Further, some RTOs/ISOs may not conduct studies 
of the economic benefits of all transmission projects. We invite 
further comment on current RTO/ISO practices with regard to the 
dissemination of production cost modeling information and the 
derivation of benefit-to-cost ratios and whether these practices could 
hamper an applicant from using the RTO/ISO modeling results to seek an 
ROE incentive for economic benefits.
    53. In addition, we recognize that public utilities outside of 
RTOs/ISOs may face challenges in using their transmission planning 
region's existing processes for analyzing the economic benefits of 
transmission projects to produce benefit-to-cost analyses for use in an 
ROE incentive application. Given non-RTO/ISO regions' lack of 
centrally-cleared markets that allow them to determine how a new 
transmission facility will change production costs or the price that 
load must pay at wholesale for electricity, their economic analyses 
vary greatly from those that RTO/ISO transmission planning regions 
conduct. Some of the non-RTO/ISO transmission planning regions--
WestConnect, ColumbiaGrid, Northern Tier Transmission Group, and 
Florida Reliability Coordinating Council (FRCC)--consider some form of 
economic benefits as part of their regional cost allocation methods. 
For example, under WestConnect's regional cost allocation method for 
regional transmission projects driven by economic considerations, 
WestConnect identifies the benefits and beneficiaries of a proposed 
regional transmission facility by modeling the potential of that 
transmission facility to support more economic, bilateral transactions 
between generators and loads in the region.\61\ FRCC's process includes 
a cost-benefit ratio calculation for transmission projects in 
consideration in its regional transmission plan based on avoided 
project cost benefits, alternative project cost benefits, and 
transmission line loss benefits.\62\ Whereas, in SERTP, the process 
mainly focuses on a power flow analysis, and includes such metrics as 
avoided costs of displaced transmission, and thermal and voltage 
constraints.\63\ We invite comment on the availability and 
accessibility of adjusted production cost and similar economic benefit 
measurement data that applicants could use to analyze the economic 
benefits of a transmission project for purposes of seeking an ROE 
incentive in non-RTO/ISO regions. We also seek comment on any economic 
calculations that entities in non-RTO/ISO regions perform in their 
transmission planning processes (whether economic calculations from 
transmission planning regions or by public utilities), and the extent 
to which it might be feasible to calculate benefit-to-cost ratios for 
any transmission projects for which these transmission projects' 
developers might consider seeking an economic benefit incentive.
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    \61\ See WestConnect, WestConnect Regional Planning Process 
Business Practice Manual, sec. 4.6.1.2.
    \62\ See FRCC regional transmission planning process, sec. 
7.2.2.
    \63\ See, for example, SERTP 2019 Transmission Planning 
Analyses, Part II.
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    54. Applicants, either in RTOs/ISOs or non-RTO/ISO transmission 
planning regions, seeking such incentives may produce their own 
benefit-to-cost study of economic benefits for their transmission 
projects for consideration by the Commission. Such studies may be 
prepared by applicants, third party consultants or, if offered, by 
transmission planning regions. These studies should include 
quantitative and qualitative description and analysis, including 
description of any cost or benefit analysis for the transmission 
project by transmission planning regions or the applicant in 
transmission planning regions, and detailed analysis and supporting 
testimony for the applicant's calculation of the transmission project's 
economic benefits, including major model assumptions, costs, and the 
resulting benefit-to-cost ratio. However, such non-RTO/ISO-performed 
studies will not receive a presumption that they are appropriately 
included in a determination of economic benefits. We invite comment on 
what supporting information and analysis an applicant's benefit-to-cost 
study should include.
    55. More generally, we also seek comment on how measurement of 
economic benefits can be distinguished from measurement of other types 
of benefits considered for purposes of

[[Page 18792]]

other incentives so that double counting of benefits does not occur.
d. Establishing a Benefit-to-Cost Threshold for Economic Incentives
    56. We believe that transmission projects should offer 
substantially more economic net benefits than the average transmission 
project to be eligible for an incentive premised upon economic 
benefits. We also believe that it is reasonable to analyze transmission 
projects by size based on the cost of the transmission project. Thus, 
we propose to use $25 million, adjusted annually for inflation,\64\ as 
a reasonable dividing line between small system modifications and 
significant transmission facility expansions. We find that these two 
categories merit separate benefit-to-cost thresholds. We propose to 
implement procedures that will provide for inputting and calculation of 
new national benefit and cost data and the resulting benefit-to-cost 
threshold between small system modifications and significant 
transmission facility additions at five-year intervals.
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    \64\ We also propose a $25 million threshold for incentives for 
pilot programs discussed in section IV.G.3.b.
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    57. As a first step toward developing national benefit-to-cost 
ratios, we examined 41 economic transmission projects selected in the 
regional transmission plans of MISO,\65\ CAISO,\66\ and PJM \67\ from 
2013 through 2019.\68\ Of these transmission projects, 11 cost more 
than $25 million and, for these transmission projects, the average 
benefit-to-cost ratio was 3.63. To be eligible for an ex-ante economic 
benefits ROE incentive, we propose that transmission projects must 
demonstrate net benefit ratios consistent with the 75th percentile of 
all transmission projects more than $25 million in these regional plans 
over the study period, which was 3.98. We note that consideration of 
benefit-to-cost ratios in other transmission planning regions would 
help to further support the thresholds for an economic benefits ROE 
incentive and we propose to expand the derivation of percentile 
thresholds through examination of benefit-to-cost ratios in other 
regions, if available, in any final rule. We seek comment on combining 
different RTO/ISO benefits measurement methodologies as part of an 
effort to derive a national benefit-to-cost threshold and the merits 
and downsides to doing so. Further, we encourage additional RTOs/ISOs 
to provide benefit-to-cost information to make these threshold figures 
more robust. Finally, we request comment on whether the benefit-to-cost 
ratio threshold calculations for the transmission projects should 
include the costs of ROE incentives.
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    \65\ MISO transmission projects included projects selected based 
upon their economic benefits as market efficiency projects and other 
economic projects. Multi-Value Projects were excluded because MISO's 
benefit-to-cost ratios do not differentiate between economic, 
reliability, and public policy requirement benefits.
    \66\ CAISO transmission projects considered are those coming out 
of CAISO's economic planning study of its Transmission Planning 
Process.
    \67\ PJM transmission project types studied included those 
designated by PJM as Market Efficiency Projects.
    \68\ Specifically, CAISO from 2013-2019; MISO and PJM from 2015-
2019. These analyses, based upon publicly available data, are 
available in Appendix A.
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    58. For transmission projects that cost less than or equal to $25 
million, the average benefit-to-cost ratio for the 30 qualifying 
transmission projects in MISO, CAISO, and PJM was 26.67, and the ratio 
for the 75th percentile transmission project was 33.91, which we 
propose to use as the threshold for an ex-ante economic benefit ROE 
incentive for these transmission projects.
    59. We also propose to offer an additional 50-basis-point incentive 
for economic benefits as measured on an ex-post basis. To be eligible 
for an ex-post economic benefits incentive, a transmission project must 
exhibit a benefit-to-cost ratio in the top 10 percent of transmission 
projects at the time of transmission project completion based on 
applying their actual costs to the projected benefits. Like the ex-ante 
economic benefit ROE incentive, a successful applicant would start 
earning this incentive in the rate year in which the transmission 
facility is placed in service. We considered using ex-post benefits 
versus projected benefits in this analysis, but concluded that the 
burden of determining and measuring such benefits, and the potentially 
significant amount of potential changes in transmission project 
benefits for reasons outside of the control of developers, makes such 
ex-post review inappropriate. By contrast, application of actual cost 
information is relatively uncontroversial and straight-forward. For the 
study period, the 90th percentile for all transmission projects in the 
three regions greater than $25 million would be 5.17, and 77.04 for 
transmission projects equal to or less than $25 million.
    60. We believe that providing an opportunity for an additional, ex-
post incentive for an applicant would benefit customers by further 
incentivizing transmission project developers to meet a transmission 
project's projected benefit-to-cost estimates by completing their 
transmission projects at or below projected costs. We seek comment on 
whether the Commission should exclude costs resulting from factors 
beyond a developer's control from the ex-post analysis for an ex-post 
economic benefits ROE incentive. However, regardless of cost overruns, 
an applicant would remain eligible for the ex-ante economic benefit ROE 
incentive. Given that these ratios are significantly above the average 
of transmission projects premised upon economic benefits, we believe 
that these incentives are directed to transmission projects that are 
more beneficial than the average transmission project.
    61. To further explain the economic benefits ROE incentive, 
assuming, for example, that a transmission project has estimated 
benefits of $400 million, ex-ante estimated costs of $100 million and 
ex-post, final actual costs of $75 million, such a transmission project 
could earn up to 50 basis points for demonstrating the 3.98 ex-ante 
threshold ($400M/$100M=4.00) and up to an additional 50 basis points 
for achieving the 5.17 ex-post threshold ($400M/$75M=5.33) after the 
transmission project is completed. We seek comment on this approach 
and, more generally, on the manner in which these thresholds are 
calculated.
    62. We propose to establish a construct for the determination of 
applicable benefit-to-cost thresholds that would also provide for 
reevaluation of these thresholds every five years based upon a 
reexamination of transmission projects selected in transmission 
planning regions based upon their economic benefits. We also propose to 
update for inflation the dividing line between small and large 
transmission projects for the purpose of determining the respective 
thresholds for these transmission projects annually.
2. Reliability Benefits
    63. FPA section 219(a) directs the Commission to establish 
incentive-based rate treatments to benefit consumers by ensuring 
reliability and FPA section 219(b)(1) directs the Commission to promote 
reliable and economically efficient transmission.\69\ Although 
reliability is clearly delineated as a benefit to be promoted by 
incentives, we are cognizant of our differing but related mandates for 
promoting reliability under FPA sections 215 and 219.
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    \69\ 16 U.S.C. 824s(a)-(b)(1).
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    64. Pursuant to FPA section 215, the Commission has approved a set 
of mandatory reliability standards developed by the North American 
Electric Reliability Corporation (NERC).

[[Page 18793]]

The NERC reliability standards define the reliability requirements for 
the planning and operation of the bulk power system, including 
transmission facility planning, emergency preparedness, voltage and 
balancing, and interconnection, among others. Transmission projects 
required to comply with these standards are assured recovery of all 
prudently incurred costs pursuant to FPA section 219(b)(4)(A).\70\ In 
accordance with the aim of FPA section 215, the NERC reliability 
standards provide for an adequate level of reliability.\71\ In light of 
these mandatory reliability standards, and the guaranteed cost recovery 
pursuant to FPA section 219(b)(4)(A), additional transmission 
incentives are not necessary to maintain an adequate level of 
reliability. Nevertheless, as explained below, we believe that a 
changing electric grid presents reliability challenges that merit 
increased capital investment in transmission facilities. We therefore 
propose in Sec.  35.35(d)(1)(iii) of the revised Transmission 
Incentives Regulations to provide an ROE incentive for certain 
transmission projects that produce significant and demonstrable 
reliability benefits above and beyond the requirements of the NERC 
reliability standards.
---------------------------------------------------------------------------

    \70\ Id. at 824s(b)(4)(A).
    \71\ Id. at 824o(a)(3).
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a. Reliability Incentive Proposal
    65. We propose in Sec.  35.35(b)(1)(iii) of the revised 
Transmission Incentives Regulations to offer a separate ROE incentive 
of up to 50 basis points for transmission projects that provide 
significant and demonstrable reliability benefits. At the outset, we 
acknowledge that reliability benefits are often more difficult to 
quantify than economic benefits. Nevertheless, FPA section 219(a) 
directs the Commission to establish incentive-based rate treatments for 
the purpose of benefiting consumers by ensuring reliability. 
Accordingly, to better align our incentives policy with the goals of 
FPA section 219, we propose to adopt an approach that quantitatively 
evaluates the reliability benefits of proposed transmission projects 
when feasible, but also recognizes the value of qualitative assessments 
of enhanced reliability. We plan to offer reliability benefit ROE 
incentives for all types of transmission projects within the 
Commission's jurisdiction that can demonstrate the showing described 
below.
    66. Reliability benefits can take many forms. A transmission 
project may provide one exceptional reliability benefit or a portfolio 
of several reliability benefits. Each transmission project has unique 
attributes, so we propose to evaluate the merits of an application for 
a reliability ROE incentive based on the transmission project providing 
one or more significant and demonstrable reliability enhancements. The 
Commission will evaluate each application on a case-by-case basis.
    67. We propose a nonexclusive set of examples and demonstrations 
that could form the basis of a showing of significant and demonstrable 
reliability benefits that a transmission project could provide. We note 
that, as this is not an exclusive list, there may be transmission 
projects with other significant and demonstrable reliability benefits 
that warrant incentives. Accordingly, we invite comment on other types 
of reliability benefits in addition to those discussed below.
    68. A transmission project may demonstrate reliability benefits in 
any number of ways. First, transmission projects that significantly 
increase import or export capability between balancing authorities can 
provide significant and demonstrable reliability benefits. For example, 
increasing import capability can provide access to additional 
generation capacity which could be necessary to prevent load shedding 
or restore load generation balance in an emergency. In addition, 
creating additional transmission capability on frequently constrained 
interfaces can reduce the likelihood of a System Operating Limit 
exceedance that can damage equipment and disrupt system operations.
    69. Second, transmission projects that result in an Interconnection 
Reliability Operating Limit (IROL) being downgraded to a routine System 
Operating Limit likely produce significant and demonstrable reliability 
benefits. The NERC reliability standards define IROLs as a sub-set of 
system operating limits that are more likely to result in severe 
cascading, instability, or uncontrolled separation if violated. 
Pursuant to the NERC standards, there are no limits on the number of 
IROLs an entity can have in its footprint, and, in fact, registered 
entities are required to designate new IROLs where applicable criteria 
are met. Similarly, transmission projects that are likely to reduce the 
frequency and/or duration of IROL exceedances can also provide 
significant and demonstrable reliability benefits.
    70. Third, transmission projects that improve the bulk power 
system's ability to operate reliably during foreseen and unforeseen 
contingencies beyond the NERC transmission planning (TPL) requirements 
or other local planning criteria, can provide significant and 
demonstrable reliability benefits. For example, an applicant may 
demonstrate that its proposed transmission project improves system 
stability margins on transfer paths or in generation or load pockets in 
its request for a reliability ROE incentive. We propose that an 
applicant may demonstrate this type of reliability benefit in a variety 
of ways, including by showing reduced loss of load probability, reduced 
need for reliability unit commitments, or by reducing unserved energy 
under various contingencies.
    71. Fourth, transmission projects that reduce the complexity of the 
transmission system by eliminating the need for one or more remedial 
action schemes \72\ on the system can provide significant and 
demonstrable reliability benefits. We propose that an applicant can 
demonstrate that its proposed transmission project ensures reliability 
by the elimination of complex remedial action schemes, which can in 
turn lower the risk of misoperations due to design errors, relay 
failures, or communication failures.
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    \72\ NERC defines a remedial action scheme as a scheme designed 
to detect predetermined system conditions and automatically take 
corrective actions that may include, but are not limited to, 
adjusting or tripping generation, tripping load, or reconfiguring a 
system.
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    72. Finally, transmission projects that use network management 
technologies, such as dynamic line ratings, power flow controls, or 
transmission topology optimization, can provide significant and 
demonstrable reliability benefits by giving operators better tools to 
address unforeseen system conditions. While these investments may not 
be required to meet reliability standards, they can expand the event 
response capabilities of the transmission system by enhancing 
situational awareness and facilitating faster response times to 
mitigate system disturbances, thus improving reliability. Accordingly, 
we propose that an applicant may demonstrate enhanced reliability 
through deployment of these technologies. Although we are proposing 
specific incentives to facilitate investment in transmission 
technologies,\73\ we also propose to consider the reliability benefits 
offered by including these technologies in transmission projects to the 
extent that these technologies add to or improve the reliability of a 
transmission project as a whole. A transmission project may offer 
reliability benefits both because of, and independent of, the inclusion 
of transmission technologies.
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    \73\ See infra section IV.G.2.

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[[Page 18794]]

    73. In addition to the five examples of types of reliability 
transmission projects discussed above, which are likely to meet the 
Commission's test of providing significant and demonstrable reliability 
benefits, we encourage applicants to propose other transmission 
projects that they think provide significant and demonstrable 
reliability benefits. We recognize the importance of maintaining a 
transmission system that can withstand extreme environmental and other 
disruptive events and remain operational in the face of such 
challenges, which can vary based on geographic region and system 
topology. Accordingly, we will also consider transmission projects that 
improve resilience in awarding reliability incentives.\74\ Transmission 
projects that provide resilience benefits in areas where they are 
needed could include the hardening of transmission assets against 
adverse weather events, fires, and geomagnetic disturbances, or event 
recovery investments such as transmission facilities related to 
blackstart facilities. Investments in transmission facilities for 
purposes of disaster recovery, such as transformers and circuit 
breakers, or other used and useful equipment for emergency response and 
recovery, also are potential investments that could be considered for a 
reliability incentive.
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    \74\ See Grid Reliability and Resilience Pricing and Grid 
Resilience in Regional Transmission Organizations and Independent 
System Operators, 162 FERC ] 61,012, at P 23 (2018) (proposing 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'').
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b. Proposed Showing and Commission Analysis
    74. In order to provide incentives for increasing system 
reliability, we propose to award up to 50 basis points for a 
transmission project that provides one or more significant and 
demonstrable reliability benefits to address specific reliability 
needs. The reliability incentives will be added to the applicant's base 
ROE and will be subject to the 250-basis-point ROE incentives cap, as 
described below.\75\ We propose that applicants should support their 
requests by providing a quantitative analysis of a transmission 
project's potential reliability benefits, where possible. Such analyses 
should include, for example, reduced loss of load probability, reduced 
unserved energy under various contingencies, reductions in reliability 
unit commitments, increases in import or export capability, and 
improvements in voltage stability. We would then review the potential 
reliability benefits to determine whether and how much of an ROE 
incentive the transmission project should be awarded. If an applicant 
is not able to provide a quantitative analysis, we also propose to 
consider qualitative demonstrations that a transmission project 
provides one or more significant and demonstrable reliability benefits 
to address specific reliability needs.
---------------------------------------------------------------------------

    \75\ See infra section IV.C.
---------------------------------------------------------------------------

    75. We seek comment as to whether there are different and/or 
additional elements that affect the reliability of the transmission 
system that we should consider in our analysis for reliability ROE 
incentives. If so, we request that commenters explain how a 
transmission project improves various elements of system reliability, 
how an applicant can demonstrate that a transmission project provides 
these benefits quantitatively or qualitatively in the absence of a 
quantitative analysis, and how we can measure or evaluate that 
demonstration.

C. Ensuring Reasonableness of ROE

    76. In addition to ensuring an ROE that is sufficient to attract 
investment in transmission facilities, the Commission must also ensure 
that rates adopted under this policy remain just and reasonable and not 
unduly discriminatory or preferential under FPA sections 205 and 
206.\76\ In Order No. 679, the Commission required that any ROE 
incentives would be subject to the total ROE remaining within the zone 
of reasonableness and found that an ROE within the zone of 
reasonableness would be adequate to attract new investment.\77\ Due to 
changing investment conditions, we propose to change the current policy 
of interpreting FPA section 219(d) to require that the ROE, inclusive 
of any incentives, remain within the zone of reasonableness. We propose 
to allow the ROE incentives to exceed the zone of reasonableness when 
added to the base ROE. However, we are proposing to modify Sec.  
35.35(b)(2) of the Transmission Incentives Regulations to cap ROE 
incentives, including incentives to attract new investment, for 
increasing reliability, for transmission technology investment, and for 
joining and remaining in a Transmission Organization, to a total of no 
more than 250 basis points, as explained further below. Consistent with 
Congressional directive in FPA section 219(d), all ROE incentives must 
be just and reasonable.
---------------------------------------------------------------------------

    \76\ 16 U.S.C. 824s(d).
    \77\ Order No. 679, 116 FERC ] 61,057 at PP 2, 91-93. The 
Commission assembles and uses the zone of reasonableness in its 
evaluation of the justness and reasonableness of public utility ROEs 
in order to balance the interests of investors and consumers. See 
Emera Maine v. FERC, 854 F.3d 9, 20-21 (DC Cir. 2017) (Emera Maine).
---------------------------------------------------------------------------

    77. The Commission has previously recognized that its obligations 
under FPA sections 219 and 205 overlap in significant ways, and it may 
be difficult to meaningfully distinguish between an ROE that 
appropriately reflects a public utility's risk and an incentive ROE to 
attract new investment.\78\ Nevertheless, the Commission is ``obligated 
to establish ROEs for public utilities that both reflect the financial 
and regulatory risks attendant to a particular transmission project and 
that are sufficient to actively promote capital investment.'' \79\ 
Although the Commission previously harmonized these principles under 
the zone of reasonableness, we believe that a change in policy 
recognizing these differences is justified.
---------------------------------------------------------------------------

    \78\ Order No. 679-A, 117 FERC ] 61,345 at P 15.
    \79\ Id.
---------------------------------------------------------------------------

    78. Our proposal recognizes that base ROE and transmission ROE 
incentives serve different functions. The Commission has found that 
base ``ROE `should be commensurate with returns on investments in other 
enterprises having corresponding risks' and `sufficient to assure 
confidence in the financial integrity of the enterprise, so as to 
maintain its credit and attract capital.' '' \80\ This is different 
from FPA section 219(b)(2), which provides that the Commission should 
offer a return on equity that attracts new investment in transmission 
facilities (including related transmission technologies). The 
Commission has explained that, ``[i]n contrast to a base-level ROE that 
reflects the financial and regulatory risks of an investment, an 
`incentive' has been more typically associated with specific basis 
point additions to a base ROE to satisfy discrete policy objectives.'' 
\81\ Therefore, the returns provided by base ROE serve a different 
purpose than the separate grant of authority in FPA section 219(b)(2) 
to provide a return on equity that attracts new investment in 
transmission facilities (including related transmission technologies). 
We find that the different purpose for an incentive ROE adder than for 
a base ROE provides that ROE incentives may be just and reasonable 
under different circumstances than base ROEs. Therefore, ROE incentives 
may meet a different test for just and reasonable

[[Page 18795]]

rates than for a base ROE, and ROE incentives that are added to the 
base ROE are, therefore, not required to be bound by the zone of 
reasonableness in order to be just and reasonable and not unduly 
discriminatory.
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    \80\ Emera Maine, 854 F.3d at 20 (citing FPC v. Hope Nat. Gas 
Co., 320 U.S. 591, 603 (1944); Bluefield Waterworks & Improvement 
Co. v. Pub. Serv. Comm'n of W. Va., 262 U.S. 679, 692-93 (1923)).
    \81\ Order No. 679-A, 117 FERC ] 61,345 at n.19.
---------------------------------------------------------------------------

    79. In Order No. 679, the Commission found that allowing ROE 
incentives up to the upper end of the zone of reasonableness was 
consistent with FPA section 205 and was ``adequate to attract new 
investment and consistent with the intent of Congress in FPA section 
219.'' \82\ Nevertheless, given the Commission's experience with the 
transmission incentives policy under FPA section 219, we believe that 
this existing limit on ROE incentives may no longer be adequate to 
attract new investment in transmission facilities, as required by FPA 
section 219. For example, the traditional starting point for analyzing 
the base ROEs of a group of utilities with above average risk is the 
upper midpoint of the zone of reasonableness, but, if the Commission 
were to retain ROE incentive limits based on the upper end of the zone 
of reasonableness, the proximity of the base ROEs of such average 
utilities to that upper end may prevent them from receiving the 
incentives granted by the Commission under FPA section 219 in order to 
provide a rate of return that attracts new investment. Limiting ROE 
incentives to the zone of reasonableness may undermine the Commission's 
ability to recognize and address the separate need to attract new 
investment and exposes transmission investment receiving incentive 
rates to the additional risk that changes to the public utility's risk 
profile may lower the incentives granted by the Commission. We do not 
believe it was the intent of Congress to preclude utilities with above-
average risk profiles from receiving ROE incentives. Therefore, we 
propose to remove this restriction and recognize that rates outside the 
zone of reasonableness can be just and reasonable, subject to the 
following restriction.
---------------------------------------------------------------------------

    \82\ Order No. 679, 116 FERC ] 61,057 at P 93.
---------------------------------------------------------------------------

    80. In place of limiting ROE incentives to the zone of 
reasonableness, we propose to establish a cap on total ROE incentives 
applicable to all public utilities regardless of their associated risk 
profiles. Since Order No. 679, the Commission has regularly reduced an 
applicant's requested ROE incentive when the cumulative number has 
appeared high based on the risks of the transmission project.\83\ In 
order to provide applicants additional certainty on how the Commission 
will review requests for ROE incentives, we propose to adopt a 250-
basis-point cap for all ROE incentives consistent with our precedent 
and propose that ROE incentives up to and including this cap will be 
just and reasonable as required by section 219(d). However, as 
discussed above, this cap would not be subject to the zone of 
reasonableness used to establish a public utility's base ROE.
---------------------------------------------------------------------------

    \83\ See, e.g., Atl. Grid Operations A LLC, 135 FERC ] 61,144, 
at PP 7, 128 (2011) (reducing a requested 300 basis point ROE 
incentive to 250 basis points); Primary Power, LLC, 131 FERC ] 
61,015, at PP 8, 152 (2010) (reducing a requested 300 basis point 
ROE incentive to 200 basis points), order on reh'g, 140 FERC ] 
61,052 (2012), pet. for review dismissed sub. nom, Public Service 
Elec. and Gas Co. v. FERC, 783 F.3d 1270 (2015); N.Y. Reg'l 
Interconnect, Inc., 124 FERC ] 61,259, at PP 2, 44 (2008) (reducing 
a requested 400 basis point ROE incentive to 275 basis points).
---------------------------------------------------------------------------

    81. We seek comment on this proposal, including on the level of the 
cap on the ROE incentives requested by applicants. In light of the 
changes in base ROE policy, we also seek comment on whether the 
Commission should allow applicants, on a case-by-case basis, to seek 
removal of the zone-of-reasonableness conditions placed on previously 
granted incentives and to replace those restrictions with a hard cap on 
the incentives they have been granted.

D. Non-ROE Incentives

    82. We propose in Sec.  35.35(d)(2)-(7) of the revised Transmission 
Incentives Regulations to continue to provide non-ROE incentives.\84\ 
These incentives will be available to all transmission projects that 
demonstrate that they either ensure reliability or reduce the cost of 
delivered power by reducing transmission congestion. These incentives 
include: Abandoned Plant Incentive, CWIP Incentive, hypothetical 
capital structures, accelerated depreciation for rate recovery, and 
regulatory asset treatment.\85\ These incentives facilitate the 
development of beneficial transmission and are consistent with a 
benefits-based approach. Applicants for these incentives will remain 
eligible for the rebuttable presumptions that transmission projects 
which are approved through regional transmission planning processes or 
state siting approvals ensure reliability or reduce the cost of 
delivered power by reducing congestion.\86\
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    \84\ These incentives are provided under Sec.  35.35(d)(1)(ii)-
(viii) of the currently effective Transmission Incentives 
Regulations.
    \85\ See 18 CFR 35.35(d)(1)(ii)-(viii).
    \86\ Id. at 35.35(i).
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    83. We continue to believe that an overly rigid approach to 
hypothetical capital structures may discourage the development of 
transmission projects and recognize that the instances where 
hypothetical capital structure are and can be used reflect unique 
circumstances.\87\ Accordingly, we propose in Sec.  35.35(d)(4) of the 
revised Transmission Incentives Regulations to allow applicants to 
request a hypothetical capital structure and will continue to evaluate 
such requests on a case-by-case basis. An applicant must demonstrate 
that the proposed hypothetical capital structure is suited to the 
unique circumstances of its transmission project as part of its showing 
that the requested incentives are just and reasonable and not unduly 
discriminatory.
---------------------------------------------------------------------------

    \87\ See Order No. 679, 116 FERC ] 61,057 at PP 132, 134.
---------------------------------------------------------------------------

    84. Additionally, we recognize that transmission planning and 
selection has changed significantly since the issuance of Order Nos. 
679 and 679-A, particularly with the implementation of Order No. 1000. 
We believe that these changes should be reflected in our transmission 
incentives policy and, therefore, propose to revise Sec.  35.35(j)(2) 
of the Transmission Incentives Regulations to change the start of the 
effective date for the Abandoned Plant Incentive from the date that the 
Commission issues an order granting 100 percent recovery of abandoned 
plant costs to the date that transmission projects are selected in a 
regional transmission planning process for the purposes of cost 
allocation. Starting the eligibility period for the Abandoned Plant 
Incentive at the date of approval by the Commission leads to the 
exclusion of costs incurred between approval of the transmission 
project by the regional transmission planning process and Commission 
approval of the incentive, and this delay is not warranted for purposes 
of cost control, because the transmission planner has made the decision 
to undertake the transmission project.\88\ Under this proposal, in 
order to recover any costs under the Abandoned Plant Incentive, an 
applicant must continue to demonstrate in a FPA section 205 filing that 
the transmission projects were abandoned for reasons outside of its 
control and that the costs incurred were prudent.
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    \88\ See, e.g., American Electric Power Company, Inc., Docket 
No. PL19-3-000, Comments, at 18 (filed June 26, 2019) (AEP 
Comments); Pacific Gas & Electric Company and San Diego Gas & 
Electric Company, Comments, Docket No. PL19-3-000, at 11-13 (filed 
June 26, 2019).

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[[Page 18796]]

E. Incentives Available to Transcos

1. Background and Experience to Date
    85. In Order No. 679, the Commission acknowledged the promise of 
Transcos in catalyzing needed investment in transmission facilities 
that further FPA section 219's policy objectives of ensuring 
reliability and reducing the cost of delivered power by reducing 
transmission congestion.\89\ The Commission stated that Transcos ``have 
demonstrated the capability to invest, on a timely basis, significant 
amounts of capital in transmission projects and in efforts to reduce 
congestion.'' \90\ The Commission attributed the positive record of 
Transco investment in transmission facilities to the stand-alone nature 
of these entities, which the Commission believed: (1) Reduced the 
competition between generation and transmission functions within 
corporations; (2) produced incentives to better manage transmission 
assets and develop innovative services; (3) granted better access to 
capital markets given a more focused business model; and (4) enabled 
better responses to market signals that indicate when and where 
transmission investment is needed. The Commission also noted that, 
unlike many traditional public utilities, Transcos avoid potential 
uncertainty associated with the need for additional rate recovery 
approval from state regulators.\91\
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    \89\ Order No. 679, 116 FERC ] 61,057 at P 206; Promoting 
Transmission Investment through Pricing Reform, Notice of Proposed 
Rulemaking, 113 FERC ] 61,182, at P 38 (2005) (2005 Transmission 
Incentives NOPR).
    \90\ 2005 Transmission Incentives NOPR, 113 FERC ] 61,182 at P 
38.
    \91\ Id. P 39.
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    86. In recognition of these beneficial attributes and a desire to 
promote and remove barriers to Transco formation, the Commission 
formalized two incentives available exclusively to Transcos: (1) An ROE 
incentive to be applied to an eligible Transco's entire rate base 
(Transco ROE Incentive),\92\ and (2) an alternative ratemaking 
treatment that adjusts the book value of transmission assets being sold 
to a Transco to remove the disincentive associated with the impact of 
accelerated depreciation on federal capital gains tax liabilities 
(Transco ADIT Adjustment).\93\ Regarding the Transco ROE Incentive, the 
Commission's policy requires that any incentive ROE awarded to Transcos 
both encourage their formation and be sufficient to attract investment 
after the Transco is formed.\94\ Regarding the Transco ADIT Adjustment, 
the Commission indicated that it would continue to consider requests 
for that ratemaking treatment on a case-by-case basis when a Transco is 
purchasing existing transmission facilities.\95\
---------------------------------------------------------------------------

    \92\ 18 CFR 35.35(d)(2)(i); Order No. 679, 116 FERC ] 61,057 at 
P 221.
    \93\ 18 CFR 35.35(d)(2)(ii); Order No. 679, 116 FERC ] 61,057 at 
PP 247-248.
    \94\ 18 CFR 35.35(d)(2); Order No. 679, 116 FERC ] 61,057 at P 
221.
    \95\ Order No. 679, 116 FERC ] 61,057 at P 248.
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    87. As discussed above, in the nearly 14 years since Order No. 679, 
there have been significant developments in how transmission is 
planned, developed, operated, and maintained. When the Commission 
adopted Order No. 679, there was a shortage of transmission investment 
and development. The Commission recognized the potential of Transcos to 
assist in addressing the lack of transmission development and 
formalized the Transco ROE Incentive to encourage these capabilities. 
However, we have not seen evidence of Transcos delivering the outcomes 
that the Commission had expected in establishing Transco incentives in 
Order No. 679.
    88. For instance, in Order No. 679, the Commission articulated an 
expectation that Transcos would be uniquely positioned to build, on a 
timely basis, significant amounts of transmission assets to further the 
policy objectives of FPA section 219.\96\ The Commission's expectation 
was based, in part, on observations of high levels of deployment of 
transmission plant among Transcos prior to Order No. 679.\97\ However, 
with hindsight, we have found that those investment levels were 
transitory, and that Transcos are deploying capital to support 
transmission development in a manner that is comparable and not 
significantly greater than that of their traditional public utility 
counterparts.\98\ Several commenters similarly note that Transcos have 
not exhibited the remarkable levels of transmission investment on which 
the Commission justified the Transco ROE Incentive.\99\
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    \96\ Id. PP 225-226; see also 2005 Transmission Incentives NOPR, 
113 FERC ] 61,182 at P 38.
    \97\ Order No. 679, 116 FERC ] 61,057 at P 222.
    \98\ For example, transmission plant growth rates for 
subsidiaries of ITC Holdings Corp., a large Transco holding company, 
are within the normal range of other transmission owners in MISO, 
where those subsidiaries operate.
    \99\ Aluminium Association, et al., Joint Comments, Docket No. 
PL19-3-000, at 67 (filed June 26, 2019) (Joint Commenters Comments); 
Resale Power Group of Iowa Comments, Docket No. PL19-3-000, at 22-23 
(filed June 26, 2019) (Resale Power Comments); Transmission Access 
Policy Study Group Comments, Docket No. PL19-3-000, at 93 (filed 
June 26, 2019) (TAPS Comments).
---------------------------------------------------------------------------

    89. Additionally, in Order No. 679 the Commission found that 
concerns regarding high rates for Transco customers were 
speculative.\100\ However, experience to date has shown those concerns 
to be valid. For example, the network rates for ITC Midwest, a 
subsidiary of ITC Holdings Corp., have been the highest in MISO since 
2010, while network rates for its sister company Michigan Electric 
Transmission Company have exceeded the MISO median in all but one year 
since 2009.\101\ Some commenters also echo concerns regarding elevated 
rates among Transcos.\102\ Against this backdrop, we note that several 
commenters argue that increasingly robust transmission planning 
processes--in part because of the independent role of RTOs/ISOs and 
Commission reforms such as Order No. 1000--may have helped achieve 
investment outcomes comparable to those envisioned by the Commission in 
Order No. 679 when it established the Transco ROE Incentive.\103\
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    \100\ Order No. 679, 116 FERC ] 61,057 at P 228.
    \101\ This reflects our analysis of MISO's Open Access 
Transmission, Energy and Operating Reserve Markets Tariff Schedule 9 
Network Rates posted on MISO's Open Access Same-Time Information 
System. See MISO, Transmission Rate Information, https://www.oasis.oati.com/woa/docs/MISO/MISOdocs/Transmission_Rates.html.
    \102\ Resale Power Comments at 26; Joint Commenters Comments at 
68.
    \103\ Resale Power Comments at 21-22; TAPS Comments at 93; Joint 
Commenters Comments at 67; Oklahoma Corporation Commission Comments, 
Docket No. PL19-3-000, at 1 (filed June 27, 2019) (Oklahoma 
Commission Comments).
---------------------------------------------------------------------------

    90. Furthermore, the Transco business model that the Commission 
envisioned in approving Transco incentives under FPA section 205 and 
then in Order No. 679 was one of robust independence.\104\ However, 
currently, the majority of Transcos have started out as, or become, 
transmission affiliates of integrated utilities.\105\ Such entities do 
not provide assurance of an absence of conflicts of interest with 
generation-owning affiliates or of a singular focus on transmission 
investment and operation. Further, the availability of these incentives 
for Transcos has not elicited the formation of many new Transcos. Since 
2006, the Commission has granted the Transco ROE Incentive to 12 
entities,\106\ some of which never

[[Page 18797]]

developed any transmission and several of which are affiliated with 
other Transcos. Meanwhile, transmission-only entities that may not 
qualify for, or have not requested, the Transco ROE Incentive have 
continued to invest in transmission and, notably, participate in 
competitive transmission solicitations.
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    \104\ See Order No. 679, 116 FERC ] 61,057 at P 202.
    \105\ The ITC companies were acquired by Fortis Inc., which owns 
multiple vertically integrated utilities. See Fortis Inc., 156 FERC 
] 61,219, at P 1 (2016), order on clarification, 158 FERC ] 61,019 
(2017). NextEra Energy, which owns, NextEra Energy Transmission, 
also owns Florida Light and Power Company and a portfolio of 
generation resources across the country. See NextEra Energy 
Transmission, LLC, 166 FERC ] 61,188, at PP 3-6 (2019).
    \106\ The Commission granted a Transco ROE Incentive in the 
following 12 cases: GridLiance West Transco LLC, 164 FERC ] 61,049 
(2018); NextEra Energy Transmission N.Y., Inc., 162 FERC ] 61,196 
(2018); Midcontinent Indep. Sys. Op., Inc., 150 FERC ] 61,252 
(2015), order on clarification and reh'g, 154 FERC ] 61,004 (2016); 
Desert Southwest Power, LLC, 135 FERC ] 61,143 (2011); Atl. Grid 
Operations A LLC, 135 FERC ] 61,144; Western Grid Development, LLC, 
130 FERC ] 61,056, order on reh'g, 133 FERC ] 61,029 (2010); Primary 
Power, 131 FERC ] 61,015; Green Energy Express LLC, 129 FERC ] 
61,165 (2009), order on reh'g, 130 FERC ] 61,117 (2010); Green Power 
Express LP, 127 FERC ] 61,031 (2009), order on reh'g, 135 FERC ] 
61,141 (2011); ITC Great Plains, LLC, 126 FERC ] 61,223 (2009), 
order on reh'g, 150 FERC ] 61,225 (2015); N.Y. Reg'l Interconnect, 
124 FERC ] 61,259; Startrans IO, L.L.C., 122 FERC ] 61,306 (2008), 
order on reh'g, 133 FERC ] 61,154 (2010).
---------------------------------------------------------------------------

2. Proposed Revisions to Transco Incentives
    91. We acknowledge the role that individual Transcos have played, 
and continue to play, in deploying new transmission infrastructure; 
however, we believe that the Transco business model has not enhanced 
the deployment of transmission infrastructure sufficiently to justify 
incentives based on this business model beyond those incentives 
available to all public utilities. We find that the circumstances have 
changed significantly since Order No. 679 and that the key reasoning 
underpinning the Commission's policy for establishing a Transco ROE 
Incentive and a Transco ADIT Adjustment no longer apply. Accordingly, 
we propose to revise our regulations to eliminate both of those 
incentives prospectively by removing current sections 35.35(b)(1) and 
35.35(d)(2) of the Transmission Incentives Regulations. Although we 
propose to eliminate those incentives exclusively available to 
Transcos, we do not revoke eligibility for Transcos to seek the 
incentives available to all public utilities as proposed in this NOPR. 
We view the suite of incentives for which Transcos (and all public 
utilities) remain eligible, in addition to those incentive proposals 
contemplated elsewhere in this NOPR, as sufficient to attract capital 
needed to achieve the transmission investment objectives articulated in 
FPA section 219. We invite comment on this proposal. We also seek 
comment regarding how the Commission should treat Transco ROE 
Incentives that were previously granted.

F. Incentives for RTO Participation

1. Background and Experience to Date
    92. FPA section 219(c) requires the Commission to ``provide for 
incentives to each transmitting utility or electric utility that joins 
a Transmission Organization.'' In Order No. 679, the Commission found 
that the RTO-Participation Incentive should be granted to utilities 
that ``join and/or continue to be a member of an ISO, RTO, or other 
Commission-approved Transmission Organization.'' \107\ The Commission 
declined to make a finding on the appropriate size or duration of the 
RTO-Participation Incentive, but noted that the basis for providing the 
incentive to existing members ``is a recognition of the benefits that 
flow from membership in such organizations and the fact [that] 
continuing membership is generally voluntary.'' \108\ The Commission 
also declined to create a generic ROE incentive for such membership, 
and instead decided that it would consider the appropriate ROE 
incentive when public utilities requested it on a case-by-case 
basis.\109\ Although the Commission declined to make a finding on the 
appropriate size or duration of the incentive in Order No. 679, 
applicants have subsequently requested a uniform, 50-basis-point level 
for demonstrating they have joined an RTO or ISO, which the Commission 
has granted without modification.
---------------------------------------------------------------------------

    \107\ Order No. 679, 116 FERC ] 61,057 at P 326.
    \108\ Id. PP 327, 331.
    \109\ Id. P 327.
---------------------------------------------------------------------------

    93. The stated purpose of FPA section 219 is to provide incentive-
based rate treatments that benefit consumers by ensuring reliability 
and reducing the cost of delivered power by reducing transmission 
congestion. We believe the RTO-Participation Incentive has not only 
encouraged the formation of and participation in RTOs/ISOs, but also 
has resulted in significant benefits for consumers. Specifically, PJM 
estimates that the total annual benefits and savings to PJM's customers 
in the 13 states and the District of Columbia in which it operates to 
be between $3.2 and $4 billion; \110\ SPP estimates that savings from 
its markets and transmission planning services provide more than $2.2 
billion annual benefits to its members at a benefit-to-cost ratio of 
14-to-1; \111\ and MISO estimates that MISO delivered between $3.2 
billion and $3.9 billion in regional benefits in 2018.\112\ Although 
RTO/ISO participation provides substantial benefits for customers, we 
agree with commenters that the RTO-Participation Incentive also 
compensates transmitting utilities for the ongoing duties and 
responsibilities of RTO/ISO membership.\113\
---------------------------------------------------------------------------

    \110\ See PJM Interconnection, L.L.C., Comments, Docket No. 
PL19-3-000, at 6-7 (filed June 26, 2019) (PJM Comments).
    \111\ See SPP, 14-to-1 The Value of Trust, at 3 (May 29, 2019), 
https://spp.org/documents/58916/14-to-1%20value%20of%20trust%2020190524%20web.pdf.
    \112\ See MISO, 2019 Value Proposition, at 5 (Feb. 7, 2020), 
https://cdn.misoenergy.org/20200214%202019%20Value%20Proposition%20Presentation425712.pdf.
    \113\ See Edison Electric Institute Comments, Docket No. PL19-3-
000, at 23 (filed June 26, 2019) (EEI Comments); PJM Comments at 4-
5.
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    94. In Order No. 679, the Commission stated that the basis for the 
RTO-Participation Incentive is ``a recognition of the benefits that 
flow from membership in such organization and the fact [that] 
continuing membership is generally voluntary.'' \114\ The RTO-
Participation Incentive was not only intended to induce transmitting 
utilities to turn over operational control over their transmission 
facilities to Transmission Organizations, but also to recognize the 
benefit to consumers of RTO/ISO membership by ensuring reliability and 
reducing the cost of delivered power by reducing congestion. Experience 
to date has demonstrated that the benefits from membership in a 
Transmission Organization is significant regardless of the 
voluntariness of such membership. These benefits include access to 
large competitive markets, optimization of the transmission system, 
regional transmission planning that supports more efficient or cost-
effective transmission development to meet regional transmission needs, 
reduction of the costs of carrying reserves through reserve sharing, 
and increased access to an expanded set of diverse resources. All of 
these attributes reduce the cost of delivered power by facilitating 
broader and more robust access to more sources of power, and to the 
lowest-cost source of power, over a wide geographic footprint. These 
benefits have increased over time. PJM notes that its value proposition 
for consumers has increased over the past 13 years to a current 
estimate of $3.2 to $4.0 billion,\115\ an increase from an estimated 
$2.2 billion in 2011.\116\
---------------------------------------------------------------------------

    \114\ Order No. 679, 116 FERC ] 61,057 at P 331.
    \115\ PJM Comments at 7.
    \116\ See FERC, 2011 Report to Congress on Performance Metrics 
for Independent System Operators and Regional Transmission 
Organizations, app. H at 313 (Apr. 2011), https://www.ferc.gov/industries/electric/indus-act/rto/metrics/pjm-rto-metrics.pdf.
---------------------------------------------------------------------------

    95. FPA section 219(c) contains no requirement that participation 
in an RTO/ISO must be voluntary to merit the

[[Page 18798]]

incentive; rather, it states the Commission shall provide for 
incentives. Neither the benefits that customers receive from a 
transmitting utility's or electric utility's membership in an RTO/ISO, 
nor the burden imposed upon the transmitting utility or electric 
utility, are diminished if the transmitting utility or electric utility 
is required by law to join an RTO or ISO.
    96. The duties and responsibilities associated with RTO/ISO 
membership have also increased since Order No. 679. These include: loss 
of operational control of transmission facilities to a third party; an 
obligation to build new transmission facilities at the direction of the 
RTO/ISO; diminished decision-making control over assets while retaining 
the responsibility of maintaining the system; meeting reliability 
standards; obligations to obey RTO/ISO rules; and an obligation to 
provide electric service even when foundational agreements can change, 
thereby changing the terms and conditions under which the transmitting 
utility initially agreed to participate in the RTO/ISO.\117\ These 
responsibilities similarly persist regardless of the voluntariness of 
RTO/ISO membership.
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    \117\ See, e.g., EEI Comments at 22; Ameren Services Company 
Comments, Docket No. PL19-3-000, at 24 (filed June 26, 2019); AEP 
Comments at 13.
---------------------------------------------------------------------------

2. RTO-Participation Incentive Proposal
    97. We propose to combine and modify Sec. Sec.  35.35(b)(2) and 
35.35(e) of the existing Transmission Incentives Regulations in Sec.  
35.35(f) of the revised Transmission Incentives Regulations to provide 
transmitting utilities that turn over their wholesale transmission 
facilities to the RTO/ISO \118\ a fixed 100-basis-point RTO-
Participation Incentive, and modify its implementation, as discussed 
below. The benefits of having centralized electricity markets and 
regional transmission planning conducted by an RTO/ISO, combined with 
compensating RTO/ISO participants for their added responsibilities, 
support the Congressional mandate of an RTO-Participation Incentive to 
encourage transmitting utilities to turn planning and operational 
control over their transmission facilities to Transmission 
Organizations. Standardizing and increasing the level at which this 
incentive is awarded reasonably recognizes the increased customer value 
resulting from transmitting utilities joining and continuing to 
participate in an RTO/ISO since the issuance of Order No. 679. It also 
recognizes the increased duties and responsibilities associated with 
RTO/ISO membership since the issuance of Order No. 679, including, 
inter alia, the development of regional transmission planning 
processes. These additional roles and responsibilities of RTOs/ISOs and 
their transmission owners have benefited customers, as illustrated by 
the increased and substantial benefits demonstrated by RTOs/ISOs. For 
instance, as noted above, PJM has stated that its value proposition for 
consumers is $3.2 to $4.0 billion in annual savings, an increase from 
an estimated $2.2 billion in 2011. Additionally, from 2007 through 
2019, the Value Proposition study revealed that MISO provided the 
region an estimated $26 billion in cumulative net benefits.\119\ In 
order to address regulatory uncertainty and fulfill our directive to 
offer an incentive for RTO membership, we find that the RTO-
Participation Incentive remains an effective incentive to recognize the 
benefits, risks, and associated obligations of RTO membership and meet 
the requirements of FPA section 219(c).
---------------------------------------------------------------------------

    \118\ 16 U.S.C. Sec. 824s(c). While the rest of the proposals in 
this proposed rule apply to public utilities, the proposal in the 
section related to RTO participation apply to ``transmitting 
utility'' or ``electric utility'' as required by Congress in FPA 
section 219(c).
    \119\ MISO, 2019 Value Proposition, at 3 (Feb. 7, 2020), https://cdn.misoenergy.org/20200214%202019%20Value%20Proposition%20Presentation425712.pdf.
---------------------------------------------------------------------------

    98. As noted by commenters to the 2019 Notice of Inquiry, 
permitting some RTO/ISO members to receive the RTO-Participation 
Incentive, while disallowing the RTO-Participation Incentive for 
entities that are required to join or remain in an RTO/ISO, would 
create an uneven playing field in the competition for investment 
capital.\120\ Such an uneven playing field has the potential to distort 
investment decisions within interstate corporate families and within 
multistate RTOs/ISOs. Furthermore, FPA section 219 obligates the 
Commission to provide an incentive to each transmitting utility or 
electric utility that joins a Transmission Organization, independent of 
the obligation to do so.\121\ We also note that the issue of whether 
RTO/ISO membership is voluntary for certain transmitting utilities 
within RTOs/ISOs has become subject to litigation and challenges at the 
Commission.\122\ Accordingly, we propose that the RTO-Participation 
Incentive should be applied to transmitting utilities that join and 
remain enrolled in an RTO/ISO regardless of the voluntariness of their 
participation.
---------------------------------------------------------------------------

    \120\ EEI Comments at 23-24.
    \121\ 16 U.S.C. 824s(c).
    \122\ See Cal. Pub. Util. Comm'n v. FERC, 879 F.3d 966, 980 (9th 
Cir. 2018) (remanding to the Commission the issue of whether PG&E 
was eligible for a 50-basis-point RTO-Participation Incentive for 
its continued participation in CAISO in light of protestors' 
arguments that PG&E's participation in CAISO is mandated by 
California state law); N.Y. State Dept. of Pub. Serv., Protest, 
Docket No. ER20-715-000, at 5 (filed Jan. 21, 2020) (protesting that 
Central Hudson Gas & Electric Corp. should not receive an RTO-
Participation Incentive because it is already a member of NYISO).
---------------------------------------------------------------------------

    99. We propose to continue to permit transmitting utilities or 
electric utilities that join an RTO/ISO the ability to recover 
prudently incurred costs associated with joining the RTO/ISO in their 
jurisdictional rates. Additionally, we propose to standardize the RTO-
Participation Incentive at a uniform level of 100 basis points to a 
transmitting utility that joins and continues to be a member of an RTO/
ISO and turns over operational control of its wholesale transmission 
facilities to the RTO/ISO.\123\ We propose that both transmitting 
utilities newly joining an RTO/ISO and those that already receive the 
current RTO-Participation Incentive would be eligible to seek the new 
100-basis-point adder. We request comment on this proposal, including 
comment on what process the Commission should adopt to implement a 
100basis point RTO-Participation Incentive for existing transmitting 
utility rates.
---------------------------------------------------------------------------

    \123\ See PPL Elec. Util. Corp., 123 FERC ] 61,068, at P 35 
(2008) (finding that a ``50-basis-point adder is appropriate. The 
consumer benefits, including reliable grid operation, provided by 
such organizations are well documented and consistent with the 
purpose of [FPA] section 219. The best way to ensure these benefits 
is to provide member utilities of an RTO with incentives for joining 
and remaining a member.''); Republic Transmission, LLC, 161 FERC ] 
61,036, at P 33 (2017) (approving 50-basis-point RTO-Participation 
Incentive ``based on Republic's commitment to become a member of 
MISO and transfer operational control of the Project to MISO once 
the Project has been placed in service''); Pac. Gas & Elec. Co., 148 
FERC ] 61,195, at P 16 (2014) (granting request for a 50-basis-point 
RTO-Participation Incentive ``based on [Pacific Gas and Electric 
Company's (PG&E)] commitment to remain a member of CAISO, and its 
commitment to transfer functional control of the Project to CAISO 
once the Project enters service'').
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G. Incentives for Transmission Technologies

1. Background and Experience to Date
    100. FPA section 219(b)(3) directs the Commission to encourage 
deployment of transmission technologies and other measures to increase 
the capacity and efficiency of existing transmission facilities and 
improve the operation of the transmission facilities.\124\ Under the 
2012 Policy Statement, the Commission considers the incorporation of 
advanced technologies to transmission projects as part of the risks and 
challenges that may

[[Page 18799]]

warrant an increase in the ROE. The Commission evaluates deployment of 
advanced technologies as part of the overall nexus analysis when an 
incentive ROE is sought; there is currently no standalone incentive for 
advanced technology. Additionally, the current framework does not 
provide a standalone incentive for technology improvements to existing 
transmission projects. Experience to date suggests that this approach 
to incentivizing transmission technologies has not been effective in 
encouraging deployment of such improvements. For example, many 
transmission technologies discussed at the November 5-6, 2019 Grid-
Enhancing Technologies Workshop \125\ are smaller in scale, and do not 
face the same challenges as large capital-intensive transmission 
projects, such as siting and regulatory approvals.\126\ Furthermore, 
many of the costs of transmission technologies are not currently 
capitalized and hence do not benefit from ROE incentives.\127\
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    \124\ 16 U.S.C. 824s(b)(3).
    \125\ FERC, Grid-Enhancing Technologies, Notice of Workshop, 
Docket No. AD19-19-000 (Sept. 9, 2019).
    \126\ See, e.g., Advanced Energy Economy, Comments, Docket No. 
PL19-3-000, at 20 (filed June 26, 2019) (Advanced Energy Economy 
Comments); Energy Storage Association, Comments, Docket No. PL19-3-
000, at 4 (filed June 25, 2019); Public Interest Organizations, 
Comments, Docket No. PL19-3-000, at 35 (filed June 26, 2019); 
Oklahoma Commission Comments at 1; TAPS Comments at 101; National 
Grid USA, Comments, Docket No. PL19-3-000, at 42 (filed June 26, 
2019).
    \127\ See, e.g., Advanced Energy Economy Comments at 20; 
Oklahoma Commission Comments at 1; Working for Advanced Transmission 
Technologies, Comments, Docket No. PL19-3-000, at 4 (filed June 26, 
2019).
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2. Proposed Incentives
    101. To comply with the directives of FPA section 219(b)(3) and 
more effectively promote the deployment of transmission technologies, 
we propose to add Sec.  35.35(e) of the revised Transmission Incentives 
Regulations to offer rate treatments for transmission technologies 
that, as deployed in certain circumstances, enhance reliability, 
efficiency, capacity, and improve the operation of new or existing 
transmission facilities. Examples of technology types that represent 
such technologies in certain deployments at this time include: (1) 
Advanced line rating management; (2) transmission topology 
optimization; and (3) power flow control. For purposes of these 
incentives, we will generally not consider eligible transmission 
technologies to include transmission system assets traditionally 
associated with the transportation of electric power, such as power 
lines, power poles, capacitors, and other substation equipment.
    102. In order to encourage the development of the technology for 
particular needs identified in different transmission planning 
processes, we decline to list the types of technologies eligible for 
transmission technology incentives. Instead, we will make a case-by-
case determination of eligibility based on the characteristics of the 
technology and the benefits that the technology offers.
    103. We propose that each public utility seeking incentives under 
this section must demonstrate that the technology, as applied in a 
particular transmission project (or stand-alone transmission technology 
project as described below), meets the above criteria for eligible 
transmission technologies and that the transmission technology project 
meets the economic benefits ROE incentive benefit-to-cost threshold 
proposed in this NOPR.\128\ Developers seeking to deploy a transmission 
technology that meets these requirements may apply for a 100-basis-
point ROE incentive on the cost of the specified transmission 
technology project (Transmission Technology Incentive) and a two-year 
regulatory asset treatment for costs related to deploying and operating 
that technology (Deployment Incentive). While the two proposed 
incentives are intended to work in conjunction, to accommodate unique 
accounting practices and flexibility, each incentive may be sought 
individually.
---------------------------------------------------------------------------

    \128\ See supra section IV.B.1.d.
---------------------------------------------------------------------------

    104. Noting that in response to the 2019 Notice of Inquiry and the 
Grid-Enhancing Technologies Workshop, we received feedback on alternate 
incentive proposals for transmission technologies, we seek comment on 
the proposed Transmission Technology Incentive and Deployment Incentive 
to effectively promote the deployment of transmission technologies.
a. Transmission Technology Incentive
    105. We propose to add Sec.  35.35(e) of the revised Transmission 
Incentives Regulations so that a public utility seeking to deploy 
transmission technologies that enhance reliability, efficiency, 
capacity, and improve the operation of new or existing transmission 
facilities may seek a 100-basis-point ROE Transmission Technology 
Incentive on the cost of the specified transmission technology project. 
The Transmission Technology Incentive may be applied to deployment of 
such technologies on either a new or existing transmission facility and 
is subject to the overall 250-basis-point cap proposed in this 
NOPR.\129\ Because the proposed Transmission Technology Incentive is 
only applicable to the costs of the particular transmission technology, 
inclusive of any costs awarded regulatory asset treatment (as discussed 
below), the amount included in the 250-basis-point limit for an 
applicant seeking transmission incentives on its transmission project 
will be calculated on a weighted average, based on the cost of the 
technology relative to the cost of the entire  transmission project.
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    \129\ See supra section IV.C.
    \130\ Inclusive of any costs awarded regulatory asset treatment 
under the Deployment Incentive described below. See infra section 
IV.G.2.b.
[GRAPHIC] [TIFF OMITTED] TP02AP20.002

    106. For instance, a developer with a $100 million transmission 
project that is awarded the Transmission Technology Incentive on a $10 
million transmission technology project sub-component, would contribute 
10 basis points to its 250-basis-point cap. Conversely, if a 
transmission project developer is awarded the Transmission Technology 
Incentive for a stand-alone transmission technology project, the 
incentive would contribute 100 basis points to its 250-

[[Page 18800]]

basis-point cap. For purposes of this incentive, a stand-alone 
transmission technology project is the addition of solely a 
transmission technology to an existing transmission facility, or a 
transmission technology that by itself constitutes a new transmission 
facility.
    107. We propose this incentive mechanism to encourage the 
deployment of innovative and cost-effective technologies that will 
bring consumer saving through congestion relief and increased 
efficiency of the transmission system consistent with the goals of FPA 
section 219. We seek comment on this proposed incentive, including the 
amount of this incentive, its limitation to the cost of the specified 
transmission technology project only, and its inclusion in the 250-
basis-point cap on a weighted average. We also seek comment on whether 
this proposed incentive is proportional to the benefits offered to 
consumers by eligible transmission technologies and if this incentive 
is sufficient to attract investment in such transmission technologies.
b. Deployment Incentive
    108. There are significant upfront costs and obstacles to public 
utilities seeking to deploy transmission technologies that offer 
consumer benefits.\131\ Many of these costs reflect significant changes 
to the transmission system, such as the increase of software and 
service-based costs in transmission operations that often require 
retraining of the workforce. To overcome these obstacles and encourage 
deployment of eligible transmission technologies that will lower the 
cost of delivered power and increase reliability, we propose to add 
Sec.  35.35(e)(2) of the revised Transmission Incentives Regulations to 
allow certain initial costs related to deploying technologies that are 
traditionally expensed in the year incurred to be deferred as a 
regulatory asset and included in rate base for purposes of determining 
a public utility's return on equity. We propose to defer up to two 
years of specified initial costs for the installation and operation of 
the eligible transmission technology, that would otherwise be expensed 
in the year incurred, to be amortized over a five-year period. For 
purposes of this incentive, we propose that the two-year period of cost 
eligibility will begin at the procurement stage, exclusive of planning 
activities.
---------------------------------------------------------------------------

    \131\ See Advanced Energy Economy Comments at 20-21; Grid-
Enhancing Technologies Workshop Transcript Day 1 at 69, 77-82, 86-
91, 95-98.
---------------------------------------------------------------------------

    109. The Deployment Incentive is intended to ease the 
implementation burden for transmission technologies and incent 
developers to deploy them. As such, this incentive is only permitted 
one time per technology per applicant and will be limited to two years 
in duration. Allowing these costs in rate base prior to and during 
initial commercial operation provides a public utility with additional 
cash flow in the form of an immediate earned return. The financial 
benefit to public utilities is warranted by the increased efficiency 
and congestion savings these technologies offer to consumers.
    110. In addition to inviting comment generally on this proposed 
rate treatment, we specifically request comment on: (1) The types of 
costs that are not currently capitalized (and not currently eligible 
for the recovery of prudently incurred pre-commercial operation costs 
under the regulatory asset incentive available under Sec.  
35.35(d)(1)(iii) of the existing Transmission Incentives Regulations) 
that should be eligible for regulatory asset treatment; (2) the 
duration of the regulatory asset treatment; (3) the total amount of 
costs for deploying certain eligible transmission technologies, 
including software; and (4) whether these proposed incentives are 
sufficient to overcome obstacles to the first deployment of an eligible 
transmission technology.
3. Eligibility and Requirements
a. Transmission Technology Statement
    111. We propose to add Sec.  35.35(e)(3) of the revised 
Transmission Incentives Regulations to require each public utility 
along with its application for the Transmission Technology Incentive or 
the Deployment Incentive, to submit a transmission technology statement 
that demonstrates: How the technology meets the transmission technology 
criteria above, the expected benefits of deployment, the cost of the 
transmission technology project, the cost of the overall transmission 
project if not a stand-alone transmission technology project, the 
expected useful life of the asset, and a demonstration that the 
transmission technology meets the economic benefits threshold provided 
in this NOPR.\132\ We request comment on this proposal.
---------------------------------------------------------------------------

    \132\ See supra section IV.B.1.d.
---------------------------------------------------------------------------

b. Pilot Programs
    112. We propose to add Sec.  35.35(e)(4) of the revised 
Transmission Incentives Regulations to allow pilot programs for 
eligible transmission technologies that meet the above criteria to 
receive a rebuttable presumption of eligibility for the Transmission 
Technology Incentive and the Deployment Incentive. For purposes of 
these incentives, we propose to define a pilot program as a public 
utility-led deployment of an eligible transmission technology, with 
costs under $25 million for each eligible transmission technology 
project, that has not been deployed to or operated on more than five 
percent of the applicant's transmission system,\133\ and has a maximum 
duration of two years from installation to completion. Additionally, 
utilities that have completed a pilot program for an eligible 
transmission technology, but have not moved to deployment, will be 
eligible for the rebuttable presumption if they meet the pilot program 
criteria and demonstrate a plan for higher deployment. We seek comment 
on the limitations on pilot programs; specifically, on the percentage 
of deployment and duration of the pilot.
---------------------------------------------------------------------------

    \133\ To determine whether an applicant's pilot program is 
eligible under this sub-section, we propose to consider an 
applicant's transmission system to include any affiliate companies' 
transmission systems that are within the same region as the 
transmission technology project seeking incentives, and exclude the 
affiliate companies' transmission systems outside of that region.
---------------------------------------------------------------------------

c. Reporting Requirement
    113. We propose to add Sec.  35.35(e)(5) of the revised 
Transmission Incentives Regulations which states that each public 
utility that receives the Transmission Technology Incentive or 
Deployment Incentive must submit an annual informational filing, for 
three years after the incentive is granted, to the Commission that 
details the progress of the technology, obstacles to its deployment and 
efforts to overcome them, lessons learned, and any quantifiable data 
measuring the benefits of the transmission technology project. Any 
duplicative data already submitted under Form 730, as revised in this 
NOPR,\134\ need not be submitted. Collected data will not be used for 
ex-post analysis for the purpose of revising the awarded incentives. We 
propose to collect the data for internal analysis and provide an annual 
update of transmission technology development to benefit the industry 
and encourage widespread deployment of beneficial transmission 
technologies.
---------------------------------------------------------------------------

    \134\ See infra section IV.I.1.
---------------------------------------------------------------------------

H. Disclosure of Anticipated Incentives

    114. As discussed above, there have been significant developments 
in the regional transmission planning process since the adoption of FPA 
section 219 and the Commission's issuance of Order Nos. 679 and 679-A. 
We seek comment on whether it would be useful to require

[[Page 18801]]

a public utility seeking incentives to disclose all reasonably 
anticipated incentives to transmission planning regions as part of the 
public utility's transmission project proposal. We also seek comment on 
whether such a requirement should apply to all incentive applications 
or only to incentive applications for an increased ROE.

I. Program Management

1. FERC Form 730
    115. As stated above, FPA section 219 provides that the Commission 
is to encourage transmission development for the purpose of benefitting 
consumers. To ensure that existing and proposed incentives are 
successfully meeting the objectives of FPA section 219, the Commission 
needs industry data, projections, and related information that detail 
the level of investment and the costs and benefits of transmission 
projects. Experience to date suggests that current information 
collection related to FPA section 219 incentives is insufficient to 
determine the effectiveness of individual incentive grants, or to 
evaluate the Commission's overall incentives program.
    116. Order No. 679 established a reporting requirement associated 
with transmission projects that receive project-specific transmission 
incentives.\135\ Order No. 679 created Form 730, which contains two 
reporting tables. Table 1 is an aggregate of the spending by a public 
utility over all the transmission projects that received incentives; 
Table 2 is a project-by-project status update. Under the current rules, 
jurisdictional public utilities are required to report annually to the 
Commission, on the date on which FERC Form No. 1 (Form 1) information 
is due, the following data and projections: (subsection i) in dollar 
terms, actual investment for the most recent calendar year and planned 
investments for the next five years; and (subsection ii) for all 
current and planned investments over the next five years, a project-by-
project listing that specifies the expected completion date, percentage 
completion as of the date of filing and reasons for delay.\136\ The 
information required in Form 730 is not available from FERC Form Nos. 
1, 714, or 715, nor is it available from other federal agencies.
---------------------------------------------------------------------------

    \135\ Order No. 679, 116 FERC ] 61,057 at P 367.
    \136\ Id. P 358.
---------------------------------------------------------------------------

a. Form 730 Proposed Format Changes
    117. We propose to retain the requirement in Sec.  35.35(i) of the 
revised Transmission Incentives Regulations for public utilities that 
have been granted incentive rate treatment to file a Form 730 on an 
annual basis. However, we believe that there are several areas of 
improvement that can be made to Form 730's design to collect the 
necessary information without imposing undue burden on incentive 
recipients. The current aggregate reporting required on Form 730 can be 
difficult to interpret if the public utility has multiple transmission 
projects and multiple transmission incentive requests. The data 
reported in Table 1 is most useful when a public utility has requested 
incentives once for a single transmission project, or for multiple 
transmission projects, if a public utility reports the data in a 
project-by-project format rather than as an aggregate number.\137\ 
Accordingly, we propose to modify Sec.  35.35(i) of the revised 
Transmission Incentives Regulations to require that applicants provide 
the information on a project-by-project basis and propose other reforms 
to make the reporting requirement more effective, as detailed below.
---------------------------------------------------------------------------

    \137\ From June 2006 to March 2019, there were about 80 
different developers that requested incentives. Of these developers, 
60 have requested incentives only once.
---------------------------------------------------------------------------

    118. We invite comment on the proposed modifications to the basic 
format and fields of Form 730,\138\ specifically:
---------------------------------------------------------------------------

    \138\ See Appendix B for a full draft of the proposed revised 
Form 730. These changes include the changes to the instructions 
requested by OMB and adopted by the instant final rule issued 
concurrently with this NOPR. Additional changes to Form 730 to track 
transmission project benefits are described in a section below.
---------------------------------------------------------------------------

    a. Require Table 1 data to display project-by-project data instead 
of aggregated data.
    b. Identify each transmission project by a public utility-created 
transmission project code in each record of Table 1 and Table 2 to aid 
in merging the tables.
    c. Add the report year to each record of Table 1 and Table 2.
    d. Add the aggregate of actual spending on each transmission 
project prior to the report year to determine total actual spending on 
each transmission project for each year.
    e. Add the aggregate of projected spending on each transmission 
project more than five years beyond the report year to estimate 
projected spending on each transmission project for each year.
    f. Include a new column entitled ``Notes on Table 1'' that permits 
a 60-character text string, so public utilities can explain any issues 
in the data. Public utilities also have the option to add a footnote 
with no character limit to describe issues in as much detail as 
necessary. For example, public utilities can explain why cost forecasts 
have suddenly increased from a previous year.
    g. Include Project Voltage as a field in Table 2. Previously, 
transmission project voltage was part of Project Description in Table 
2. If no value can be used as the transmission project voltage, the 
number -9 is inserted to indicate that there is no value.
    h. The data in Table 2 must be known as of midnight on December 31 
of the record year. This is a clarification of a point of ambiguity in 
the original description of Table 2.
    i. Modify the data in the column titled, ``If Project Not On 
Schedule, Indicate Reasons For Delay'' in Table 2 to a 60-character 
text string. Public utilities also have the option to add a footnote 
with no character limit so utilities can explain the reasons in more 
detail.
    j. Report Form 730 data in eXtensible Business Reporting Language 
(XBRL). format.
    119. The change to the XBRL data format for Form 730 reporting is 
consistent with the Commission's planned change to XBRL for Form 1 
reporting.\139\ The Commission has examined the transition to XBRL in 
depth and has provided justification and support for this change in 
data reporting format.\140\ The same justifications apply in this 
context. For instance, XBRL will not only be a standard data format at 
the Commission; it is an international standard for digital reporting, 
and it enables the reporting of comprehensive, consistent, 
interoperable data that allows industry and other data users to 
automate submission, extraction, and analysis. XBRL is a language in 
which reporting terms can be authoritatively defined, and those terms 
can then be used to uniquely represent the contents of the Commission's 
data collections. XBRL is currently required for filing forms by a 
number of other federal agencies.
---------------------------------------------------------------------------

    \139\ Revisions to the Filing Process for Commission Forms, 
Notice of Proposed Rulemaking, 166 FERC ] 61,027 (2019).
    \140\ Id. PP 4-18.
---------------------------------------------------------------------------

    120. Additionally, XBRL provides an efficient way to exchange 
information inherent to the XML format and applies a standard way to 
capture the characteristics of that information. The XBRL standard also 
offers flexible benefits, including the ability to support simple 
formulas such as addition and subtraction and allow more complex 
formulas to be defined with a set of guidelines. We believe that 
requiring XBRL-based data would also lead to

[[Page 18802]]

greater data quality through easier validation checks.
    121. The transition to XBRL format will require modifications to 
the format of the current Form 730 Tables. However, the modifications 
and the data format reporting adjustments are justified by the 
aforementioned benefits, such as efficiency, consistency, and 
flexibility. We invite comment on the proposed changes to Form 730.
2. Scope of Public Utility Reporting Obligation
    122. We propose to modify the scope of the public utilities 
reporting obligation for Form 730 to direct all public utilities that 
receive an incentive, other than the RTO-Participation Incentive, for 
any transmission project to submit information on Form 730 regardless 
of the transmission project's size. Currently, Order No. 679 only 
requires information reporting for transmission projects that cost $20 
million or more \141\ and we propose to eliminate this threshold. 
However, we propose that public utilities that receive only the RTO-
Participation Incentive must report only for transmission projects that 
cost more than $3 million.\142\ We seek comment on this general 
elimination of the threshold and the $3 million partial retention of it 
for some public utilities.
---------------------------------------------------------------------------

    \141\ See Order No. 679, 116 FERC ] 61,057 at P 370.
    \142\ The threshold of $3 million is proposed because the 
Commission has had requests for incentives for transmission projects 
as small as $3 million. See Va. Elec. Power Co., 124 FERC ] 61,207, 
at P 17 (2008).
---------------------------------------------------------------------------

    123. The expanded reporting obligation, as proposed here, would 
make Form 730 a more comprehensive forecast tool and permit the 
Commission to project how much transmission investment will occur in 
the next five years. Additionally, increasing the scope of the 
reporting requirement will allow the Commission to compare transmission 
projects and to evaluate the benefits of transmission projects awarded 
incentives. This will enable the Commission to evaluate the 
effectiveness of the incentives program and ensure that the Commission 
is meeting the statutory requirements of FPA section 219.
3. Benefits Reporting in Form 730
    124. As proposed in this NOPR, the Commission's incentive policies 
will no longer focus on risks and challenges, but instead will evaluate 
the benefits of proposed transmission projects. In order to effectively 
evaluate the benefits and monitor the progress of transmission projects 
that have received incentives, we propose to modify Form 730 to include 
benefits metrics. We propose that reporting on benefits calculations, 
both the expected and the actual, should only apply to transmission 
projects that are $25 million or more in scale to reduce the reporting 
burden.
    125. We also propose the following modifications to Form 730 to 
measure transmission project benefits:
    a. Add a new column to Table 1 for the expected annual benefits of 
each transmission project.
    b. Add a new Table 3 to record actual estimated benefits for each 
year for up to five years after the date of completion of the 
transmission project.
    c. Incorporate the data in Tables 1 through 3 of Form 730 as new 
schedules in Form 1.
    d. Require public utilities to report the estimated annual economic 
benefits of each transmission project that is under construction that 
receives any transmission incentive using the same methodology that 
would have been used to justify an economic transmission incentive 
regardless of whether that transmission project actually received an 
economic transmission incentive. Where possible, we propose to require 
such benefits to be calculated with the same methodology used by the 
RTO/ISO to determine economic benefits.
    e. Require public utilities to report actual annual economic 
benefits of completed transmission projects that received any 
transmission incentive using actual data calculated using the same 
methodology that would have been used to justify an economic 
transmission incentive regardless if that transmission project actually 
received an economic transmission incentive. Where possible, we propose 
to require economic benefits to be calculated with the same methodology 
used by the RTO/ISO to determine economic benefits.
    f. This annual economic benefit reporting requirement will be 
limited to the first full five years of the transmission project's 
implementation.
    126. We request comment on the burden to public utilities to 
provide this benefit information.

V. Information Collection Statement

    127. The information collection requirements contained in this NOPR 
are subject to review by the Office of Management and Budget (OMB) 
under section 3507(d) of the Paperwork Reduction Act of 1995.\143\ 
OMB's regulations require approval of certain information collection 
requirements imposed by agency rules.\144\ Upon approval of a 
collection of information, OMB will assign an OMB control number and 
expiration date. Respondents subject to the filing requirements of this 
rule will not be penalized for failing to respond to these collections 
of information unless the collections of information display a valid 
OMB control number.
---------------------------------------------------------------------------

    \143\ 44 U.S.C. 3507(d).
    \144\ 5 CFR 1320.11.
---------------------------------------------------------------------------

    128. This NOPR would revise the Commission's regulations and policy 
with respect to the mechanics and implementation of the Commission's 
transmission incentives policy; and with respect to the metrics for 
evaluating the effectiveness of incentives. These provisions would 
affect the following collections of information:
     FERC-516, Electric Rate Schedules and Tariff Filings 
(Control No. 1902-0096); and
     FERC-730, Report of Transmission Investment Activity 
(Control No. 1902-0239).
    129. Interested persons may obtain information on the reporting 
requirements by contacting Ellen Brown, Office of the Executive 
Director, Federal Energy Regulatory Commission, 888 First Street NE, 
Washington, DC 20426 via email ([email protected]) or telephone 
(202) 502-8663.
    130. The Commission solicits comments on the Commission's need for 
this information, whether the information will have practical utility, 
the accuracy of the burden estimates, ways to enhance the quality, 
utility, and clarity of the information to be collected or retained, 
and any suggested methods for minimizing respondents' burden, including 
the use of automated information techniques.
    131. Please send comments concerning the collection of information 
and the associated burden estimates to: Office of Information and 
Regulatory Affairs, Office of Management and Budget, 725 17th Street 
NW, Washington, DC 20503 [Attention: Desk Officer for the Federal 
Energy Regulatory Commission]. Due to security concerns, comments 
should be sent electronically to the following email address: 
[email protected]. Comments submitted to OMB should refer to 
OMB Control Nos. 1902-0096 and 1902-0239.
    132. Please submit a copy of your comments on the information 
collections to the Commission via the eFiling link on the Commission's 
website at http://www.ferc.gov. If you are not able to file comments 
electronically, please send a copy of your comments to: Federal Energy 
Regulatory Commission, Secretary of the Commission, 888 First Street 
NE,

[[Page 18803]]

Washington, DC 20426. Comments on the information collection that are 
sent to FERC should refer to RM20-10-000.
    Title: Electric Rate Schedules and Tariff Filings (FERC-516) and 
Report of Transmission Investment Activity (FERC-730).
    Action: Proposed revision of collections of information in 
accordance with RM20-10-000
    OMB Control Nos.: 1902-0096 (FERC-516) and 1902-0239 (FERC-730).
    Respondents for this Rulemaking: Public Utilities that seek 
incentive-based rate treatment for transmission projects, public 
utilities for which the Commission has granted incentive-based rate 
treatment for transmission projects, RTOs/ISOs, and the non-RTO/ISO 
planning regions.
    Frequency of Information Collection: On occasion, except for Form 
730, which must be filed annually beginning with the calendar year the 
Commission grants incentive-based rate treatment, and except for the 
transmission technology annual report, which must be filed annually.
    Necessity of Information: Required to obtain or retain benefits.
    Internal Review: The Commission has reviewed the changes and has 
determined that such changes are necessary. These requirements conform 
to the Commission's need for efficient information collection, 
communication, and management within the energy industry. The 
Commission has specific, objective support for the burden estimates 
associated with the information collection requirements.
    133. The NERC Compliance Registry, as of January 31, 2020, 
identifies approximately 337 Transmission Owners in the United States 
that are subject to this proposed rulemaking. Additionally, there are 
six RTOs/ISOs and six planning regions which are not RTOs/ISOs, for a 
total of 12 planning regions overall.
    134. The Commission estimates that the NOPR would affect the burden 
\145\ and cost \146\ of FERC-516 (eTariff Filings) and Form 730 as 
follows:
---------------------------------------------------------------------------

    \145\ ``Burden'' is the total time, effort, or financial 
resources expended by persons to generate, maintain, retain, or 
disclose or provide information to or for a Federal agency. For 
further explanation of what is included in the information 
collection burden, refer to 5 CFR 1320.3.
    \146\ Commission staff estimates that respondents' hourly wages 
(including benefits) are comparable to those of FERC employees. 
Therefore, the hourly cost used in this analysis is $80.00 ($169,091 
per year).

                                                   Proposed Changes in NOPR in Docket No. RM20-10-000
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                             Annual estimated
                                                           Annual estimated      number of                                     Total estimated  burden
           Area of modification               Number of        number of         responses      Average burden hours & cost    hours & total estimated
                                             respondents     responses per      (Column B x            per  response          cost  (Column D x  Column
                                                              respondent         Column C)                                                E)
A.                                                     B.                C.                D.  E...........................  F.
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                    FERC-516, eTariff Filings (for Planning Regions)
--------------------------------------------------------------------------------------------------------------------------------------------------------
RTO/ISO regions provide transmission                    6              1.67                10  5 hours; $400...............  50 hours; $4,000.
 planning data to developers that examine
 economic attributes of projects.
Non-RTO/ISO regions provide transmission                6              0.83                 5  5 hours; $400...............  25 hours; $2,000.
 planning data to developers that examine
 economic attributes of projects.
                                                                                                                            ----------------------------
Sub-Total for Planning Regions...........  ..............  ................  ................  ............................  75 hours; $6,000.
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                   FERC-516, eTariff Filings (for Transmission Owners)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Developers in RTO/ISO regions provide                  10                 1                10  40 hours; $3,200............  400 hours; $32,000.
 data made available by a transmission
 planning region that examines economic
 attributes of projects.
Developers in non-RTO/ISO regions submit                5                 1                 5  480 hours; $38,400..........  2,400 hours; $192,000.
 showings of proposed transmission
 projects' economic merits by using
 economic modeling within transmission
 planning regions; or provide showings of
 economic benefits as determined by third
 party experts.
Demonstration that project met or came in               5                 1                 5  120 hours; $9,600...........  600 hours; $48,000.
 under the project costs for additional
 incentive.
Demonstration of reliability benefits....              10                 1                10  360 hours; $28,800..........  3,600 hours; $288,000.
Demonstration for transmission technology              15                 1                15  40 hours; $3,200............  600 hours; $48,000.
 incentive requests.
Annual report on progress, obstacles,                  15                 1                15  400 hours; $32,000..........  6,000 hours; $480,000.
 lessons learned, and quantifiable data
 for transmission technology deployment.
                                                                                                                            ----------------------------
    Sub-Total for Transmission Owners....  ..............  ................  ................  ............................  13,600 hours; $1,088,000.
                                                                                                                            ----------------------------

[[Page 18804]]

 
        Total Proposed Changes for         ..............  ................  ................  ............................  13,675 hours; $1,094,000.
         eTariff Filings (FERC-516):.
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                        Form 730
--------------------------------------------------------------------------------------------------------------------------------------------------------
Additional reporting requirements for                  63                 1                63  6 hours; $480...............  378 hours; $30,240.
 current filers of FERC Form 730.
Additional filers of FERC Form 730.......             137                 1               137  36 hours; $2,880............  4,932 hours; $394,560.
                                                                                                                            ----------------------------
    Sub-Total of Proposed Changes for      ..............  ................  ................  ............................  5,310 hours; $424,800.
     Form 730.
                                                                                                                            ----------------------------
        Total Proposed Changes for FERC-   ..............  ................  ................  ............................  18,985 hours; $1,518,800.
         516 & Form 730 in NOPR in RM20-
         10.
--------------------------------------------------------------------------------------------------------------------------------------------------------

    135. To date, the Commission has received approximately 110 
incentive requests since Order No. 679 was issued in 2006. For the 
purposes of estimating burden in this NOPR, in the table above, we 
conservatively estimate annual numbers of the different possible 
incentive requests. We seek comment on the estimates in the table above 
regarding the number of incentive requests.
    136. With regard to eTariff Filings, as discussed above, the 
Commission proposes to change its analysis and the regulatory text to 
implement a benefits-based standard. Rather than connecting incentives 
with risks and challenges, the Commission proposes that applicants 
demonstrate that facilities receiving incentives either ensure 
reliability or reduce the cost of delivered power by reducing 
transmission congestion consistent the requirements of section 219, and 
that the resulting rates are just and reasonable. Since applicants 
already seek incentives, we estimate that the additional burden to 
applicants to be in the demonstration of economic reliability benefits 
or reliability benefits for those associated incentives, the 
demonstration for transmission technology incentives, and the reporting 
related to the transmission technology incentives. We also note that 
the transmission planning regions will also have an additional burden 
in providing information to developers. For applicants in non-RTO 
regions, we seek comment on the additional estimates of burden these 
demonstrations and information sharing will require.
    137. With regard to Form 730, the Commission estimates that the 
proposed changes will increase the amount of time required to prepare 
the information in Form 730 for public utilities that already report 
data by about 20 percent, from 30 hours to 36 hours, including the time 
for reviewing instructions, searching existing data sources, gathering 
and maintaining the data-needed, and completing and reviewing the 
collection of information. The additional form preparation time data on 
prior spending and data on total projected spending on a project-by-
project basis instead of as a total summation. It is the Commission's 
belief that public utilities are already gathering data in a project-
by-project format to prepare the total summation in Table 1, so 
requiring a report on project-by-project spending would not require 
significant additional time.
    138. Approximately 80 \147\ transmission owners have requested 
transmission incentives and, therefore, only about 80 transmission 
owners have been subject to the requirement to file Form 730. We expect 
that requiring all transmitting utilities that receive the RTO-
Participation Incentive for transmission projects that cost more than 
$3 million to report Form 730 will increase the number of utilities to 
about 150. Additionally, we conservatively estimate that, at any point 
in the future, the number of public utilities in non-RTO/ISO regions 
which may seek incentive requests to be about 50, leading to a 
conservative estimate of 200 transmission owners affected by the 
proposed changes to Form 730. We seek comment on the estimated 
additional burden and the number of transmission owners affected by the 
proposed changes to Form 730.
---------------------------------------------------------------------------

    \147\ The current OMB-approved inventory shows 63 respondents, 
so that figure is shown in the table above for the number of current 
filers (who will have an additional six hours of burden).
---------------------------------------------------------------------------

VI. Environmental Analysis

    139. The Commission is required to prepare an Environmental 
Assessment or an Environmental Impact Statement for any action that may 
have a significant adverse effect on the human environment.\148\ We 
conclude that neither an Environmental Assessment nor an Environmental 
Impact Statement is required for this NOPR under section 380.4(a)(15) 
of the Commission's regulations, which provides a categorical exemption 
for approval of actions under sections 205 and 206 of the FPA relating 
to the filing of schedules containing all rates and charges for the 
transmission or sale of electric energy subject to the Commission's 
jurisdiction, plus the classification, practices, contracts, and 
regulations that affect rates, charges, classification, and 
services.\149\
---------------------------------------------------------------------------

    \148\ Order No. 486, Regulations Implementing the National 
Environmental Policy Act, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & 
Regs. Preambles 1986-1990 ] 30,783 (1987).
    \149\ 18 CFR 380.4(a)(15).
---------------------------------------------------------------------------

VII. Regulatory Flexibility Act

    140. The Regulatory Flexibility Act of 1980 \150\ generally 
requires a description and analysis of proposed and final rules that 
will have significant economic impact on a substantial number of small 
entities. The Small Business Administration (SBA) sets the threshold

[[Page 18805]]

for what constitutes a small business. Under SBA's size standards,\151\ 
RTOs/ISOs, planning regions, and transmission owners all fall under the 
category of Electric Bulk Power Transmission and Control (NAICS code 
221121), with a size threshold of 500 employees (including the entity 
and its associates).\152\
---------------------------------------------------------------------------

    \150\ 5 U.S.C. 601-612.
    \151\ 13 CFR 121.201.
    \152\ The threshold for the number of employees indicates the 
maximum allowed for a concern and its affiliates to be considered 
small.
---------------------------------------------------------------------------

    141. The six RTOs/ISOs (SPP, MISO, PJM, ISO New England, NYISO, and 
CAISO) each employ more than 500 employees and are not considered 
small.
    142. We estimate that 337 transmission owners and six planning 
authorities are also affected by the NOPR. Using the list of 
Transmission Owners from the NERC Registry (dated January 31, 2020), we 
estimate that approximately 68% of those entities are small entities.
    143. We estimate additional annual costs associated with the NOPR 
(as shown in the table above) of:
     $480 each for 63 current filers of the Form FERC-730 and 
$2,880 each for 137 new filers of Form FERC-730
     $500 each for six RTO/ISO regions and six non-RTO/ISO 
regions to provide planning data (FERC-516)
     Costs ranging from $0 to $76,800 (for each transmission 
owner in RTOs/ISOs) to $112,000 \153\ (for each transmission owner in 
non-RTO/ISO regions) for eTariff filers (FERC-516). These costs are 
only incurred on a voluntary basis.
---------------------------------------------------------------------------

    \153\ These values represent the theoretical maximum case in 
which a Transmission Owner applies for every type of incentive, and 
also files a transmission technology annual report.
---------------------------------------------------------------------------

    144. Therefore, the estimated additional annual cost per entity 
ranges from $0 to $114,880.
    145. According to SBA guidance, the determination of significance 
of impact ``should be seen as relative to the size of the business, the 
size of the competitor's business, and the impact the regulation has on 
larger competitors.'' \154\ We do not consider the estimated cost to be 
a significant economic impact. As a result, we certify that the 
proposals in this NOPR will not have a significant economic impact on a 
substantial number of small entities.
---------------------------------------------------------------------------

    \154\ U.S. Small Business Administration, A Guide for Government 
Agencies How to Comply with the Regulatory Flexibility Act, at 18 
(May 2012), https://www.sba.gov/sites/default/files/advocacy/rfaguide_0512_0.pdf.
---------------------------------------------------------------------------

VIII. Comment Procedures

    146. The Commission invites interested persons to submit comments 
on the matters and issues proposed in this notice to be adopted, 
including any related matters or alternative proposals that commenters 
may wish to discuss. Comments are due July 1, 2020. Comments must refer 
to Docket No. RM20-10-000, and must include the commenter's name, the 
organization they represent, if applicable, and their address in their 
comments.
    147. 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.
    148. 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.
    149. 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.

IX. Document Availability

    150. 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.
    151. 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.
    152. 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 
[email protected], or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. Email the Public Reference Room at 
[email protected].

List of Subjects in 18 CFR Part 35

    Electric power rates, Electric utilities, Reporting and 
recordkeeping requirements.

    By direction of the Commission. Commissioner Glick is dissenting in 
part with a separate statement to be issued at a later date.

    Issued March 20, 2020.
Nathaniel J. Davis, Sr.,
Deputy Secretary.

    In consideration of the foregoing, the Commission proposes to amend 
part 35, chapter I, title 18, Code of Federal Regulations, as follows.

Subpart G--Transmission Infrastructure Investment Provisions

0
1. The authority citation for subpart G continues to read as follows:

    Authority:  16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 41 
U.S.C. 7101-7352.

0
2. Section 35.35 is revised to read:


Sec.  35.35   Transmission infrastructure investment.

    (a) Purpose. This section establishes rules for incentive-based 
rate treatments for transmission of electric energy in interstate 
commerce by public utilities for the purpose of benefiting consumers by 
ensuring reliability and reducing the cost of delivered power by 
reducing transmission congestion.
    (b) General rules. (1) All rates approved under the rules of this 
section, including any revisions to the rules, are subject to the 
filing requirements of sections 205 and 206 of the Federal Power Act 
and to the substantive requirements of sections 205 and 206 of the 
Federal Power Act that all rates, charges, terms, and conditions be 
just and reasonable and not unduly discriminatory or preferential.
    (2) All rates approved under the rules of this section are subject 
to a 250-basis-point cap on total return on equity incentives.
    (3) Applicants for the incentive-based rate treatment must make a 
filing with the Commission under section 205 of the Federal Power Act 
prior to recovering incentives in rates.
    (c) Applications for incentive-based rate treatments for 
transmission infrastructure investment. The Commission will authorize 
any incentive-based rate treatment, as discussed in this paragraph (c), 
for transmission infrastructure investment, provided that the proposed 
incentive-based rate treatment is just and reasonable and not unduly

[[Page 18806]]

discriminatory or preferential. An applicant's request for one or more 
incentive-based rate treatments, to be made in a filing pursuant to 
section 205 of the Federal Power Act, or in a petition for a 
declaratory order that precedes a filing pursuant to section 205 of the 
Federal Power Act, must include a detailed explanation of how the 
proposed rate treatment complies with the requirements of section 219 
of the Federal Power Act and a demonstration that the proposed rate 
treatment is just, reasonable, and not unduly discriminatory or 
preferential. The applicant must demonstrate that the facilities for 
which it seeks incentives either ensure reliability or reduce the cost 
of delivered power by reducing transmission congestion consistent with 
the requirements of section 219 and that resulting rates are just and 
reasonable.
    (d) Types of incentive-based rate treatments for all transmission 
infrastructure investment. For purposes of paragraph (c), incentive-
based rate treatment means any of the following:
    (1) A rate of return on equity sufficient to attract new investment 
in transmission facilities, including;
    (i) 50-basis-points increase in return on equity incentives for ex-
ante economic benefits;
    (ii) 50-basis-points increase in return on equity incentives for 
ex-post economic benefits;
    (iii) Up to 50-basis-points increase in return on equity incentives 
for reliability benefits;
    (2) 100 percent of prudently incurred Construction Work in Progress 
in rate base;
    (3) Recovery of prudently incurred pre-commercial operations costs;
    (4) Hypothetical capital structure;
    (5) Accelerated depreciation used for rate recovery;
    (6) Recovery of 100 percent of prudently incurred costs of 
transmission facilities that are cancelled or abandoned due to factors 
beyond the control of the applicant;
    (7) Deferred cost recovery; and
    (8) Any other incentives approved by the Commission, pursuant to 
the requirements of this section, that are determined to be just and 
reasonable and not unduly discriminatory or preferential.
    (e) Incentive-based rate treatments for investment in transmission 
technology. In addition to the incentives in Sec.  35.35(d), the 
Commission authorizes the following incentive-based rate treatments and 
requirements for transmission technology investment by utilities that 
enhance reliability, economic efficiency, capacity, and improve the 
operation of new or existing transmission facilities:
    (1) A stand-alone 100-basis-point return on equity incentive on the 
costs of the specified transmission technology project.
    (2) Regulatory asset treatment for up to two years of initial costs 
related to deploying eligible transmission technologies that are 
traditionally expensed to be deferred and included in rate base for 
purposes of determining a public utility's rate of return, and 
amortized over five years.
    (3) To be eligible to receive each incentive described in this 
subpart, each applicant must submit a transmission technology statement 
when requesting an incentive that demonstrates: how the technology 
meets the transmission technology criteria, the expected benefits of 
deployment, the cost of the transmission technology project, the cost 
of the overall transmission project if not a stand-alone transmission 
technology project, the expected useful life of the asset, and a 
demonstration that the transmission technology meets the economic 
benefits threshold.
    (4) Eligible transmission technology pilot programs will receive a 
rebuttable presumption of eligibility for the incentives described in 
this subpart.
    (5) Each applicant granted an incentive under this subpart must 
submit to the Commission an annual informational filing, for three 
years after the incentive is granted, that details the progress of the 
technology, obstacles to its deployment and efforts to overcome them, 
lessons learned, and any quantifiable data measuring the benefits of 
the transmission technology project. Any information already submitted 
to the Commission via existing forms need not be submitted under this 
requirement.
    (f) Incentives for joining and remaining in a Transmission 
Organization. For purposes of this incentive, Transmission Organization 
means 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. The Commission will permit transmitting 
utilities or electric utilities that join a Transmission Organization 
the ability to recover prudently incurred costs associated with joining 
the Transmission Organization in their jurisdictional rates. 
Additionally, the Commission will authorize a 100-basis-point increase 
in return on equity as an incentive-based rate treatment for a 
transmitting utility that joins and remains in a Transmission 
Organization and turns over operational control of the applicant's 
wholesale transmission facilities to the Transmission Organization.
    (g) Approval of prudently-incurred costs. The Commission will 
approve recovery of prudently-incurred costs necessary to comply with 
the mandatory reliability standards pursuant to section 215 of the 
Federal Power Act, provided that the proposed rates are just and 
reasonable and not unduly discriminatory or preferential.
    (h) Approval of prudently incurred costs related to transmission 
infrastructure development. The Commission will approve recovery of 
prudently-incurred costs related to transmission infrastructure 
development pursuant to section 216 of the Federal Power Act, provided 
that the proposed rates are just and reasonable and not unduly 
discriminatory or preferential.
    (i) FERC-730, Report of transmission investment activity. Public 
utilities that have been granted incentive rate treatment for specific 
transmission projects must file FERC-730 on an annual basis beginning 
with the calendar year incentive rate treatment is granted by the 
Commission. Such filings are due by April 18 of the following calendar 
year and are due April 18 each year thereafter. The following 
information must be filed:
    (1) In dollar terms, on a project-by-project basis actual 
transmission investment for the most recent calendar year, and 
projected, incremental investments for the next five calendar years;
    (2) For all current and projected investments over the next five 
calendar years, a project-by-project listing that specifies for each 
transmission project the most up-to-date, expected completion date, 
percentage completion as of the date of filing, and reasons for delays. 
Exclude from this listing transmission projects with projected costs 
less than $3 million that did not receive a project-specific 
transmission incentive; and
    (3) For good cause shown, the Commission may extend the time within 
which any FERC-730 filing is to be filed or waive the requirements 
applicable to any such filing.
    (j) Rebuttable presumption. (1) The Commission will apply a 
rebuttable presumption that an applicant has demonstrated that its 
project is needed to ensure reliability or reduces the cost of 
delivered power by reducing congestion for:
    (i) A transmission project that results from a fair and open 
regional planning

[[Page 18807]]

process that considers and evaluates projects for reliability and/or 
congestion and is found to be acceptable to the Commission; or
    (ii) A transmission project that has received construction approval 
from an appropriate state commission or state siting authority.
    (2) Effective date for abandoned plant costs: A public utility with 
a transmission project that is selected in a regional transmission 
planning process for the purposes of cost allocation can recover 100 
percent of abandoned plant costs from the date such project is selected 
in a regional transmission planning process.
    (3) To the extent these approval processes do not require that a 
project ensures reliability or reduce the cost of delivered power by 
reducing congestion, the applicant bears the burden of demonstrating 
that its project satisfies these criteria.
    (k) Commission authorization to site electric transmission 
facilities in interstate commerce. If the Commission pursuant to its 
authority under section 216 of the Federal Power Act and its 
regulations thereunder has issued one or more permits for the 
construction or modification of transmission facilities in a national 
interest electric transmission corridor designated by the Secretary, 
such facilities shall be deemed to either ensure reliability or reduce 
the cost of delivered power by reducing congestion for purposes of 
section 219(a).

    Note: The following appendices will not appear in the Code of 
Federal Regulations.

Appendix A--Benefit-Cost Data for Approved Economic Transmission 
Projects

                                       Table 1--Benefit-Cost Ratio Summary
----------------------------------------------------------------------------------------------------------------
                   Average ratio calculations                         Overall      >$25 million    <$25 million
----------------------------------------------------------------------------------------------------------------
All.............................................................           20.09            3.63           26.67
PJM.............................................................           35.12            4.95           38.30
CAISO...........................................................            3.07            1.95            5.85
MISO............................................................            6.05            4.79            6.76
Total Projects..................................................           41.00           12.00           30.00
----------------------------------------------------------------------------------------------------------------


                                     Table 2--Benefit-Cost Ratio Percentiles
----------------------------------------------------------------------------------------------------------------
                     Percentile calculations                            All        >$25 million    <$25 million
----------------------------------------------------------------------------------------------------------------
75th Percentile.................................................           15.21            3.98           33.91
90th Percentile.................................................           72.42            5.17           77.04
----------------------------------------------------------------------------------------------------------------


                                           Table 3--Economic Projects
                                           [Project cost >$25 million]
----------------------------------------------------------------------------------------------------------------
                                                                                                  Transmission
             Project                       Region                Benefit           Cost  ($)     planning cycle
----------------------------------------------------------------------------------------------------------------
Julian Hinds.....................  CAISO.................  3.75...............      32,500,000         2018-2019
S-Line series reactor project *..  CAISO.................  2.36...............      39,000,000              2018
East Marysville..................  CAISO.................  1.62...............      42,600,000         2018-2019
Delaney- Colorado River 500 kV     CAISO.................  0.94 (200 MW            501,000,000         2013-2014
 line (200 MW scenario) **.                                 scenario).
                                                           1.10 (300 MW
                                                            scenario).
Duff--Coleman 345 kV.............  MISO..................  15.80..............      49,600,000              2015
Southeast Louisiana Project......  MISO..................  2.90...............      87,700,000              2016
Western Region Economic Project    MISO..................  2.20...............     122,500,000              2015
 (WREP) (formerly known as East
 Texas Economic Project).
Huntley--Wilmarth 345 kV.........  MISO..................  1.70...............     123,530,000              2016
Hartburg to Sabine Junction 500    MISO..................  1.35...............     158,520,000              2017
 kV Economic Project (Formerly
 WOTAB 500 kV Project).
Conastone-Graceton (b2992).......  PJM...................  5.23...............      39,600,000              2018
Market Efficiency Project 9A       PJM...................  4.67...............     320,190,000              2016
 (b2743 & b2752).
----------------------------------------------------------------------------------------------------------------
* This project's benefit-cost ratio was determined to be encouraging, but CAISO earmarked it for future
  consideration once the design and configuration of this line is finalized. We included this project in our
  calculation because its ratio was deemed to be acceptable, and therefore, a valid data point for the purposes
  of contextualizing ``selectable'' B-C Ratios.
** CAISO calculated The Delaney-Colorado River 500 kV line's benefits included sensitivity analyses for both
  under 5% and 7% discount rates. We averaged the two sensitivity B-C ratios for each scenario, and present both
  instances here as sub-parts of one approved project.


                                           Table 4--Economic Projects
                                           Project cost >$25 million]
----------------------------------------------------------------------------------------------------------------
                                                                                                  Transmission
              Project                          Region              B-C Ratio         Cost        planning cycle
----------------------------------------------------------------------------------------------------------------
Giffen Line Reconductoring.........  CAISO....................            7.50       6,500,000         2018-2019
Lodi-Eight Mile 230 kV Line........  CAISO....................            4.20      10,000,000         2014-2015
Carlyss 230-138 kV Autotransformer:  MISO.....................           28.25         670,000              2017
 Upgrade Station Equipment.
Upgrade Minden--Sarepta 115 kV       MISO.....................            1.83       1,900,000              2016
 Terminal Equipment.
Elkhart Lake SS, 138 kV--Relieve     MISO.....................            3.55       2,540,000              2018
 Market Congestion.
Sam Rayburn to Doucette 138 kV:      MISO.....................            8.51       3,880,000              2017
 Upgrade Line Rating.
Mabelvale-Bryant: Reconductor 115kV  MISO.....................            5.88       6,100,000              2015
 line.

[[Page 18808]]

 
Lakeover 500/230 kV XFMR...........  MISO.....................            1.43       6,700,000              2016
Rebuild Wabaco to Rochester 161kV..  MISO.....................            6.79      12,960,000              2018
P3212: Wheatland to Breed 345 kV...  MISO.....................            1.28      14,500,000              2012
Wilson-BR Tap-Paradise 161 kV        MISO.....................            3.28      18,900,000              2018
 Modification.
Replace L7915 B phase line trap at   PJM......................            7.20         100,000              2015
 Wayne substation.
Replace terminal equipment at        PJM......................          120.83         120,000              2017
 Reynolds on the Reynolds--
 Magnetation 138kV.
Replace relays at AEP's Cloverdale   PJM......................           15.80         500,000              2015
 and Jackson's Ferry substations to
 improve the thermal capacity of
 Cloverdale--Jackson's Ferry 765 kV
 line.
Upgrade 138 kV substation equipment  PJM......................           35.80         600,000              2015
 at Butler, Shanor Manor and
 Krendale substations. New rating
 of line will be 353 MVA summer
 normal/422 MVA emergency.
Upgrade capacity on E. Frankford-    PJM......................          147.69         840,000              2017
 University Park 345kV.
Reconductor limiting span of         PJM......................           11.30       1,000,000              2017
 Lallendorf--Monroe 345kV (crossing
 of Maumee river).
Reconductor two spans of the         PJM......................            4.30       1,100,000              2015
 Graceton--Safe Harbor 230 kV
 transmission line. Includes
 termination point upgrades.
Rebuild Worcester--Ocean Pine 69 kV  PJM......................           82.70       2,400,000              2015
 ckt. 1 to 1400A capability summer
 emergency.
Reconductor three spans limiting     PJM......................           73.30       3,100,000              2015
 Brunner Island--Yorkana 230 kV
 line, add 1 breaker to Brunner
 Island switchyard, upgrade
 associated terminal equipment.
Upgrade terminal equipment on the    PJM......................           52.60       5,200,000              2015
 Lincoln--Carroll 115/138 kV path.
Upgrade substation equipment at      PJM......................           13.45       5,620,000              2017
 Pontiac Midpoint station to
 increase capacity on Pontiac-
 Brokaw 345 kV line..
Reconductor Michigan City--          PJM......................            4.93       6,000,000              2017
 Bosserman 138kV.
Reconductor Roxana--Praxair 138kV..  PJM......................            1.07       6,100,000              2017
Reconfigure Munster 345kV as ring    PJM......................            4.78       6,700,000              2017
 bus.
Rebuild the Hunterstown--Lincoln     PJM......................           76.41       7,210,000              2019
 115 kV line (No.962) (~2.6 mi.).
 Upgrade limiting terminal
 equipment at Hunterstown and
 Lincoln..
Increase ratings of Peach Bottom     PJM......................            2.60       9,700,000              2015
 500/230 kV transformer to 1479 MVA
 normal/1839 MVA emergency.
Reconductor approximately 7 miles    PJM......................            5.80      11,200,000              2015
 of the Woodville--Peters (Z-117)
 138 kV circuit.
Mitigate sag limitations on          PJM......................           64.46      11,500,000              2016
 Loretto--Wilton Center 345 kV Line
 and replace station conductor at
 Wilton Center.
Rebuild Michigan City-Trail Creek--  PJM......................            2.63      24,690,000              2019
 Bosserman 138 kV (10.7 mi).
----------------------------------------------------------------------------------------------------------------

Appendix B

OMB Control Number: 1902-0239

Expiration Date: nn/nn/nnnn

Annual Due Date: April 18


FERC-730, Report of Transmission Investment Activity

Company Name:_______________

    To file this form, respondents should follow the instructions for 
eFiling available at https://www.ferc.gov/docs-filing/efiling.asp.

Template for Table 1

                                                         Table 1--Actual and Projected Electric Transmission Capital Spending by Project
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                        Total actual and projected project spending on  transmission facilities during each time period  ($ Thousands) (1)
                                                 --------------------------------------------------------------------------------------------------------------------------------
                                      Project                 Actual                                                         Projected
  Report year      Project code     description  --------------------------------------------------------------------------------------------------------------------------------      Notes
                                                     Prior to                                                                                                      After Report
                                                    report year   Report year +0  Report year +1  Report year +2  Report year +3  Report year +4  Report year +5      year +5
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
          (2)              (3)             (4)             (5)             (6)             (7)                                                                             (8)             (9)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

    Instructions for completing ``Table 1'':
    (1) Total Actual and Projected Project Spending on Transmission 
Facilities During Each Time Period is the total actual and projected 
spending on each project until it is completed. Transmission facilities 
are defined to be transmission assets as specified in the Uniform 
System of Accounts in account numbers 350 through 359 (see, 18 CFR part 
101, Uniform System of Accounts Prescribed for Public Utilities and 
Licensees Subject to the Provisions of the Federal Power Act, for 
account definitions). The Transmission Plant accounts include: Accounts 
350 (Land and Land Rights), 351 (Energy Storage Equipment- 
Transmission), 352 (Structures and Improvements), 353 (Station 
Equipment), 354 (Towers and Fixtures), 355 (Poles and Fixtures), 356 
(Overhead Conductors and Devices), 357 (Underground Conduit), 358 
(Underground Conductors and Devices), and 359 (Roads and Trails).
    (2) Report Year is the year associated with data reported in that 
row. For

[[Page 18809]]

example, if it is April 2021 and the public utility is reporting on 
2020 project activity, the report year is 2020. A public utility can 
use the same form to correct a prior year's data. It would just report 
the data associated with the previous report year as an entry in Table 
1.
    (3) Project Code is the same Project Code associated with the 
project as in Table 2 below. Project Code is a 12-character 
alphanumeric string unique to each project. Respondents should add as 
many additional rows as are necessary to list all relevant projects. 
The combination of Report Year and Project Code is the primary key for 
each record. The primary key allows Table 1 and Table 2 data to be 
combined into a single table.
    (4) Project Description is a descriptive name for the project. It 
is the same description associated with the project code in Table 2.
    (5) Prior to the Report Year is the sum of all Actual spending 
associated with the project prior to the report year. All capital 
spending data is formatted as a currency number.
    (6) Report Year +0 is the sum of all Actual spending associated 
with the project during the report year.
    (7) Report Year +n means the sum of all Projected spending on the 
project in the calendar year of the Report Year plus n. For example, if 
n equals one, and the report year is 2020, then Report Year +1 will be 
2021 and that entry would be sum of all Projected spending on the 
project in the calendar year 2021.
    (8) After Report Year +5 means the sum of all Projected spending on 
the project more than five years past the Report Year. For example, if 
the report year is 2020, then this entry would be the sum of all 
spending starting at the beginning of 2026 and continuing until the 
project is complete. Note, that this entry can be estimated by using 
the total projected spending on the project, which the public utility 
already knows.
    (9) Notes includes information about spending and estimated 
spending not included elsewhere. Notes is a 120-character string.
    Below is an example of Table 1 associated with a fictitious public 
utility with two fictitious projects.

                                     Table 1--Actual and Projected Electric Transmission Capital Spending by Project
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                Total actual and projected project spending on transmission facilities during each
                                                                             time period ($ thousands)
                                             ----------------------------------------------------------------------------------------
  Report                        Project              Actual                                     Projected
   year     Project code      description    ----------------------------------------------------------------------------------------        Notes
                                               Prior to                                                                      After
                                                report     Report     Report     Report     Report     Report     Report     report
                                                 year     year +0    year +1    year +2    year +3    year +4    year +5    year +5
--------------------------------------------------------------------------------------------------------------------------------------------------------
     2019  AKX0303......  Piney Ridge to         $2,600    $28,500    $60,000    $60,000    $50,000         $0         $0         $0  Revision to 2019
                           Fulton.                                       (10)                                                          actual.
     2020  AKX0303......  Piney Ridge to        $31,100    $30,500    $30,000    $40,000    $50,000    $40,000         $0         $0  Cost forecasts are
                           Fulton.                                                                                                     higher and
                                                                                                                                       further out due
                                                                                                                                       to reroute.
     2020  AKX0304......  Fulton to Grey         $1,100     $1,000    $36,000    $50,000    $20,000         $0         $0         $0  N/A.
                           Pike.
--------------------------------------------------------------------------------------------------------------------------------------------------------

    (10) The developer should not revise projected data from what it 
originally reported unless the developer is correcting an obvious data 
entry mistake.
    In this example, the public utility revised the 2019 data. The 
public utility cannot revise projected data; however, it is appropriate 
to revise actual data if that data has been reported incorrectly. For 
example, in 2020 the Prior to Report Year data for project code AKX0303 
is $31.1 million. If the sum of Prior to Report Year and Report Year +0 
for project code AKX0303 and report year 2019 did not sum to $31.1 
million, then the public utility reported the data incorrectly in 2019 
and should revise those entries.

Template for Table 2

                                                             Table 2--Project Status Details
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                         Expected
                                                           Project                        project                         Was project    If project was
  Report year        Project code           Project        voltage     Project type     completion    Completion status   on schedule?  not on schedule,
                                          description        (kV)                      date  (month/                         (Y/N)      indicate reasons
                                                                                           year)                                            for delay
--------------------------------------------------------------------------------------------------------------------------------------------------------
      (1)                 (2)                 (3)            (4)           (5)              (6)              (7)              (8)              (9)
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Instructions for completing ``Table 2'':
    (1) Report Year is the year of the report data and should be the 
same as reported in Table 1. There should be no information in Table 2 
that could not be known at the end of the report year.
    (2) Project Code is a public utility-created alphanumeric 
designator twelve digits or less that is unique to each project. 
Project Code is the same project code from Table 1 above. Respondents 
must list all projects included in Table 1 that received a project-
specific transmission incentive. Projects that only received the RTO-
Participation Incentive need only be listed if they are projected to be 
at least $3 million. It can be identical to the code used by the RTO/
ISO if it is unique to the project and is 12 digits or less. This code 
never changes during the time the project is developed and is never 
reused for any subsequent project. Respondents should add as many 
additional rows as are necessary to list all relevant projects. The 
combination of Report Year and Project Code is the primary key for each 
record. The primary key allows Table 1 and Table 2 data to be combined 
into a single table.
    (3) Project Description is the same description used in Table 1 
associated with the Project Code. Respondents should incorporate the 
name given by the public utility when requesting incentives into the 
Project Description, whenever possible. The Project Description never 
changes. Project Description is a 40-character string. Respondents must 
create a Project Description, using plain English, that will uniquely 
identify the project. The same Project Description cannot be used for 
two different Project Codes and each Project Code has only one Project 
Description ever.
    (4) Project Voltage is the maximum voltage associated with the 
project. If no voltage could logically be associated the project, then 
respondents should enter a Project Voltage value of -9. Project Voltage 
is a numeric value so -9 is a way of indicating that there is no number 
for this entry.

[[Page 18810]]

    (5) Respondents should select between the following Project Types 
to complete the Project Type column: New Build, Upgrade of Existing, 
Refurbishment/Replacement, or Generator Direct Connection. Project Type 
is a 40-character string.
    (6) Expected Project Completion Date is the date the public utility 
forecasts as the date that the project will be completed at the end of 
Report Year. If the project was completed during the report year, then 
Expected Project Completion Date is the actual project completion date. 
Project Completion date is formatted mm/yyyy.
    (7) Respondents should select between the following designations to 
complete the Completion Status column: Complete, Under Construction, 
Pre-Engineering, Planned, Proposed, and Conceptual. If the project is 
completed between the end of the report year and the day the public 
utility reports the data, the Completion Status would be Under 
Construction because that was the project status at the end of the 
report year. Completion Status is a 20-character string.
    (8) Was Project on Schedule? (Y/N) is either Y (yes) or N (no) 
depending on whether the project was on schedule at the end of the 
report year. Was Project on Schedule? (Y/N) is a 1-character string.
    (9) If the Project Was Not on Schedule, Indicate Reasons for the 
Delay is a 120-character string. The utility has 120 characters to 
explain why the project was delayed at the end of the report year. If 
there was no delay at the end of the report year, then the respondent 
can just enter N/A.
    Below is an example of Table 2 associated with the same fictitious 
public utility with the same two fictitious projects as used in the 
example of Table 1.

                                                             Table 2--Project Status Details
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                         Expected                                        If the project
                                                           Project                        project                         Was  project     was not on
  Report year        Project code         Project name     voltage     Project type     completion    Completion status   on schedule?      schedule,
                                                             (kV)                      date  (month/                         (Y/N)      indicate reasons
                                                                                           year)                                          for the delay
--------------------------------------------------------------------------------------------------------------------------------------------------------
2020 (10)......  AKX0303.............  Piney Ridge to           230  New Build......         06/2024  Under              No...........  Unable to site
                                        Fulton.                                                        Construction.                     original route.
2020...........  AKX0304.............  Fulton to Grey           230  New Build......         09/2023  Pre-Engineering..  Yes..........  N/A.
                                        Pike.
--------------------------------------------------------------------------------------------------------------------------------------------------------

    (10) There is no revision for the 2019 AKX0303 Table 2 entry even 
though the public utility now knows that the route will be delayed 
because this information was not knowable at the end of the report 
year. Revisions to data are only to correct information that would have 
been known to be incorrect at the end of the report year.
    Paperwork Reduction Act of 1995 (PRA) Statement: The PRA (44 U.S.C. 
3501 et seq.) requires us to inform you the information collected in 
the Form 730 is necessary for the Commission to evaluate its incentive 
rates policies, and to demonstrate the effectiveness of these policies. 
Further, the Form 730 filing requirement allows the Commission to track 
the progress of electric transmission projects granted incentive-based 
rates, providing an accurate assessment of the state of the industry 
with respect to transmission investment, and ensuring that incentive 
rates are effective in encouraging the development of appropriate 
transmission infrastructure. Responses are mandatory. An agency may not 
conduct or sponsor, and a person is not required to respond to a 
collection of information unless it displays a currently valid OMB 
Control Number. Public reporting burden for reviewing the instructions, 
completing, and filling out this form is estimated to be 36 hours per 
response. Send comments regarding the burden estimate or any other 
aspect of this form to [email protected], or to the Office of the 
Executive Director, Information Clearance Officer, Federal Energy 
Regulatory Commission, 888 First Street NE, Washington, DC 20426.
    Title 18, U.S.C. 1001 makes it a crime for any person knowingly and 
willingly to make to any Agency or Department of the United States any 
false, fictitious, or fraudulent statements as to any matter within its 
jurisdiction.

[FR Doc. 2020-06321 Filed 4-1-20; 8:45 am]
BILLING CODE 6717-01-P