\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).
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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-

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

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

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_ADDRESS>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_ADDRESS>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,

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.
                                                                                ----------------------------

        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

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<PHONE_NUMBER> (toll free at 1-866-208-3676) or email at
<EMAIL_ADDRESS>or the Public Reference Room at (202) 502-
8371, TTY<PHONE_NUMBER>. Email the Public Reference Room at
<EMAIL_ADDRESS>
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

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

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.

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

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.

    (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