H.R. 6176

[Congressional Bills 119th Congress]
[From the U.S. Government Publishing Office]
[H.R. 6176 Introduced in House (IH)]

<DOC>

119th CONGRESS
1st Session
H. R. 6176

To require standardized performance reporting for entities engaged in 
electricity transmission to improve transparency, accountability, and 
grid outcomes, and for other purposes.

_______________________________________________________________________

IN THE HOUSE OF REPRESENTATIVES

November 20, 2025

Mr. Casten (for himself, Mr. Mullin, Mr. Huffman, Mr. Subramanyam, Mr. 
Quigley, Mr. Garamendi, Ms. Castor of Florida, Mr. Moulton, Mr. Foster, 
Mr. Levin, and Mr. Carson) introduced the following bill; which was 
referred to the Committee on Energy and Commerce

_______________________________________________________________________

A BILL

To require standardized performance reporting for entities engaged in 
electricity transmission to improve transparency, accountability, and 
grid outcomes, and for other purposes.

Be it enacted by the Senate and House of Representatives of the 
United States of America in Congress assembled,

SECTION 1. SHORT TITLE.

This Act may be cited as the ``Electricity Transmission Scorecard 
Act''.

SEC. 2. FINDINGS.

Congress finds the following:
(1) Electricity transmission facilities and services 
provided by covered transmission owners affect interstate 
commerce and are essential to the Nation's economic well-being 
and national security.
(2) Transparent, standardized performance data on 
transmission systems promotes cost-effective investment, 
prevents unduly discriminatory practices, and protects 
ratepayers.
(3) Existing reporting requirements are fragmented, 
inconsistent, and do not allow for meaningful comparison among 
transmission providers, RTOs, and ISOs.
(4) To ensure that all transmitting utilities are subject 
to uniform, non-discriminatory access obligations, to safeguard 
the public interest in the reliability, affordability, and 
efficiency of the interstate transmission system, and to ensure 
the development of just and reasonable rates, a common 
performance reporting framework is necessary.
(5) Systemic transparency across all utilities engaged in 
transmitting electricity enables ratepayers, investors, 
generators, regulators, researchers, and other stakeholders and 
market participants to clearly compare transmission rates, 
outcomes, and practices across regions and governance 
structures.
(6) Market and policy innovation in the electricity sector 
is enhanced by making grid performance data publicly available, 
thus empowering independent research, enabling competition, and 
reducing information asymmetries between utilities and external 
actors.
(7) The quality of economic, reliability, and environmental 
outcomes delivered to customers can improve as a result of 
performance-based accountability.
(8) It is in the best interest of the Nation to require 
standardized data submissions and scorecard reporting from all 
utilities engaged in transmitting electricity, including those 
not subject to section 205 or 206 of the Federal Power Act, to 
evaluate whether service comparability and nondiscrimination 
obligations are being met and to ensure that ratepayers are not 
burdened by inefficiencies, lack of investment, or the absence 
of cost-effective solutions that would increase capacity, 
reduce congestion, facilitate interconnection, or otherwise 
reduce unnecessary costs and reliability concerns for 
ratepayers.

SEC. 3. PERFORMANCE SCORECARD ELEMENTS AND VERIFICATION.

(a) Reporting Requirements.--
(1) Transmission investment, accountability, and 
performance scorecards.--
(A) In general.--The Commission shall require each 
covered transmission owner to biannually develop, 
publish, and submit to the Secretary a report, to be 
known as a Transmission Investment, Accountability, and 
Performance Scorecard (or a TIAPS report), that 
includes metrics evaluating the following:
(i) Ratepayer affordability, which shall 
assess the cost of transmission services per 
unit of energy transmitted or other metrics 
that can be used to assess affordability of 
energy provided to ratepayers.
(ii) Financing costs, which shall assess 
the financing structure and cost of capital for 
a covered transmission owner, and may include 
consideration of capital structure and leverage 
ratios, reliance on formula rates or other 
automatic adjustment mechanisms, allowed and 
earned returns on equity, the cost of debt and 
preferred stock, the presence and magnitude of 
incentive rate adders, and other related 
metrics.
(iii) Investment prudency and cost 
recovery, which shall assess the prudency of 
capital investments and the transparency and 
structure of associated cost recovery 
mechanisms, and may include the frequency and 
magnitude of cost disallowances in rate 
proceedings, the types of facilities or 
investments associated with disallowed costs, 
the degree of cost recovery from ratepayers 
relative to shareholder contributions, and the 
transparency and accountability of cost 
allocation frameworks.
(iv) Investment effectiveness, which shall 
assess the value delivered by covered 
transmission owner investments relative to 
their costs, including how effectively the 
covered transmission owner considered and 
deployed the most economically efficient 
solutions to reduce cost burden on ratepayers 
and the accuracy of project cost estimates, and 
may include metrics related to benefit-cost 
analyses, investments in advanced technology 
deployment, non-wires alternatives, 
reconductoring, grid-enhancing technologies, or 
other operational upgrades that avoid higher 
cost capital investment, estimated and actual 
cost for new or updated assets, and other 
indicators of prudent capital deployment.
(v) Capital expenditure bias, which shall 
assess the covered transmission owner's balance 
of spending on capital investment versus 
operational and maintenance activities.
(vi) System reliability and availability, 
which shall assess the operational performance 
of the transmission facilities of the covered 
transmission owner over the reporting period, 
including information related to outages, 
equipment availability, and resilience to 
system disturbances, and may be expressed using 
existing transmission-specific reliability 
indicators, as described by the North American 
Electric Reliability Corporation or other 
entity established to oversee and administer 
reliability standards and procedures for the 
bulk-power system, metrics regarding the 
economic costs of outages or lost reliability, 
or other related metrics.
(vii) Physical system performance, which 
shall assess how effectively the transmission 
facilities owned, operated, or controlled by 
the covered transmission owner are used to 
deliver electricity, including both physical 
and economic performance, and may include 
technical and non-technical losses, utilization 
relative to rated capacity and design 
constraints, age of system components, and 
other indicators of transmission system 
utilization, performance, and efficiency.
(viii)(I) Interconnection and access 
fairness, which shall assess the extent to 
which the interconnection process for 
interregional interconnections and new 
facilities (including generators, energy 
storage, load, and merchant transmission 
projects) is conducted in a timely and 
impartial manner consistent with Commission 
regulations, including comparisons between 
affiliated entities and unaffiliated entities, 
and may be expressed as the difference in the 
number of days from initial interconnection 
request to execution of an Interconnection 
Agreement, or through related measures of 
procedural equity.
(II) For purposes of this clause:
(aa) The term ``affiliated entity'' 
means any entity that has a direct or 
indirect relationship with a covered 
transmission owner or its parent entity 
that could reasonably influence 
interconnection treatment, including an 
entity that--
(AA) shares common 
ownership or controlling 
interest with the covered 
transmission owner or its 
parent entity;
(BB) is a direct or 
indirect subsidiary of the 
covered transmission owner or 
its parent entity;
(CC) is engaged in a joint 
venture, contractual 
partnership, or strategic 
alliance with the covered 
transmission owner or its 
parent entity, where such 
partnership includes shared 
financial interest, revenue 
sharing, or asset co-
development; or
(DD) is otherwise 
determined by the Commission to 
have a financial, governance, 
or operational relationship 
that may reasonably be expected 
to influence interconnection 
prioritization.
(bb) The term ``unaffiliated 
entity'' means any entity that--
(AA) has logged an 
interconnection request with 
the covered transmission owner; 
and
(BB) is not an affiliated 
entity.
(ix) Non-operational cost recovery, which 
shall assess the amount of covered transmission 
owner spending on lobbying, advertising, 
penalties, and advocacy activities recovered 
through customer rates, and may be expressed as 
expenditures on each such activity, a total sum 
of expenditures on such activities, or related 
metrics.
(x) Interregional and regional planning 
integration, which shall assess the extent to 
which the covered transmission owner 
participates in coordinated regional and 
interregional transmission planning processes 
and infrastructure development, and may be 
expressed as the number and capacity of 
interregional transmission ties, the share of 
projects subject to regional or interregional 
planning review, or related metrics.
(xi) Any additional matters that--
(I) may be evaluated using outcome-
based performance metrics identified by 
the Commission, giving preference to 
quantitative metrics over qualitative 
metrics; and
(II) the Commission determines are 
necessary to improve transparency, 
affordability, reliability, equity, or 
environmental performance of the 
facilities owned, operated, or 
controlled by the covered transmission 
owner.
(B) Exemptions.--
(i) Categories.--The Commission may, by 
rule, exempt all covered transmission owners in 
a category of covered transmission owners from 
the requirement to include a metric described 
in subparagraph (A) if the Commission 
determines that the metric is demonstrably 
inapplicable to all covered transmission owners 
in the category.
(ii) Scope.--The Commission shall ensure 
that the scope of any metric from which a 
category of covered transmission owners is 
exempted under this subparagraph is as narrow 
as possible in order to preserve consistency 
and comparability among scorecards.
(C) Coordination.--In preparing and developing a 
scorecard pursuant to this paragraph, a covered 
transmission owner shall coordinate, as necessary to 
obtain or estimate data required to be included in a 
scorecard under this section, with any relevant entity, 
including--
(i) regional grid operators, including 
Independent System Operators, Regional 
Transmission Organizations, transmission 
planning entities, and balancing authorities;
(ii) interconnected electric utilities, 
including load serving entities and other 
transmission providers;
(iii) owners of generation facilities, 
including utility-scale and merchant generators 
seeking interconnection or operating within the 
service territory of the covered transmission 
owner; and
(iv) regulatory and oversight entities, 
including State public utility commissions, and 
applicable Federal or State energy, 
reliability, or environmental agencies.
(2) Regional investment, accountability, and performance 
scorecards.--The Commission shall require each Independent 
System Operator, Regional Transmission Organization, and 
transmission planning entity to annually develop, publish, and 
submit to the Secretary a report, to be known as a Regional 
Investment, Accountability, and Performance Scorecard (or a 
RIAPS report), that includes the following:
(A) Aggregation of the metrics reported for the 
year in the scorecards submitted under paragraph (1) by 
the covered transmission owners within the jurisdiction 
of the applicable ISO, RTO, or transmission planning 
entity, which shall consist of a summary of such 
metrics that--
(i) reflects weighted or capacity-adjusted 
averages of covered transmission owner-reported 
metrics, as appropriate;
(ii) highlights significant intra-regional 
variation or performance outliers; and
(iii) does not obscure material differences 
among transmission owners or regions.
(B) Regional-specific metrics, which shall consist 
of reporting on metrics specific to operational 
responsibilities of the ISO, RTO, or transmission 
planning entity, including the following:
(i) Market efficiency, which shall assess 
the extent to which the ISO, RTO, or 
transmission planning entity is successful in 
operating efficient wholesale electricity 
markets, minimizing system congestion, and 
maximizing the use of existing grid 
infrastructure to deliver cost-effective 
outcomes for consumers while maintaining 
required standards of reliability, and may be 
expressed as average energy and ancillary 
service costs (system-wide and by major zone), 
system and zonal capacity costs where 
applicable, congestion costs, out-of-market 
payments, frequency of redispatch, 
implementation of congestion-relieving 
technologies, or related metrics.
(ii) Regional interconnection performance, 
which shall assess the effectiveness and 
efficiency of interconnection processes, and 
may include metrics that measure the duration 
of queue processing, the rate of project 
withdrawals, and the share of projects that 
successfully reach commercial operation, or 
related metrics.
(iii) Regional and interregional 
development, which shall assess the extent and 
effectiveness of regional and interregional 
transmission planning and buildout, and may be 
expressed in relation to the number and total 
capacity of transmission lines developed 
through regional and interregional planning 
processes, the proportion of new transmission 
projects selected through regional planning 
processes versus those advanced outside of such 
processes (including local or supplemental 
projects), the number of projects selected 
through competitive processes, the use and 
outcomes of benefit-cost analysis in project 
selection and development, the frequency of 
stakeholder engagement, the ratio of total 
investment in interregional and regional 
transmission to investment in local 
transmission, or other related metrics.
(iv) Seams management and resolution, which 
shall assess the extent to which the ISO, RTO, 
or transmission planning entity identifies and 
addresses seams, and may include the number of 
seams-related studies initiated or completed, 
the quantity and capacity of interties enabling 
cross-regional power flows, and the frequency 
or magnitude of congestion and price divergence 
across seams.
(v) Greenhouse gas emissions intensity, 
which shall assess, through the use of 
methodologies specified by the Commission based 
on input from the Administrator of the 
Environmental Protection Agency, the emissions 
profile of electricity delivered within the 
service territory of the ISO, RTO, or 
transmission planning entity in the reporting 
year, and may be expressed as the emissions 
intensity of delivered electricity in carbon 
dioxide equivalents per megawatt-hour, or 
related metrics.
(vi) Any additional outcome-based 
performance metrics the Commission determines 
necessary to improve transparency, 
affordability, reliability, equity, or 
environmental performance of the transmission 
system overseen by the RTO, ISO, or 
transmission planning entity.
(3) Data disclosure.--Each reporting entity shall publish 
and submit to the Secretary, with each scorecard published 
under this subsection, all non-confidential underlying data 
supporting the metrics included in the scorecard, in a machine-
readable, open-data format.
(4) Initial reporting.--Each reporting entity shall publish 
and submit to the Secretary its first scorecard not later than 
6 months after the date on which the Commission issues a final 
rule under subsection (e)(1).
(b) Metric and Methodology Standardization.--
(1) In general.--The Commission, with input from the 
Secretary, the Administrator, the National Laboratories, and 
other stakeholders, where appropriate, shall standardize the 
metrics required to be included in a scorecard under subsection 
(a) and the methodologies for calculating such metrics, 
including by ensuring that the definitions, data sources, and 
calculation methodologies for each metric are uniform among all 
reporting entities, except as provided in paragraph (2).
(2) Exception for necessary regional or structural 
differences.--In carrying out paragraph (1), the Commission may 
allow for a difference among reporting entities in metrics or 
methodologies only upon issuance of a written determination 
that the difference is demonstrably necessary on a regional or 
structural basis.
(3) Benefit-cost analysis.--In carrying out paragraph (1), 
the Commission shall establish uniform requirements for any 
benefit-cost analyses to be included in a scorecard under 
subsection (a), including minimum parameters, data sources, and 
assumptions to ensure comparability among reporting entities 
and to prevent selective or undisclosed modeling assumptions 
that materially affect reported results.
(c) Verification Requirements.--
(1) In general.--The Commission shall establish a process 
by which scorecards required to be developed under subsection 
(a) are verified by independent evaluators to ensure accuracy, 
consistency, and credibility prior to publication under such 
subsection. The Commission shall include in such process--
(A) requirements for the approval by the Commission 
of independent evaluators, including requirements that 
an independent evaluator--
(i) possess demonstrated expertise in 
electric transmission planning, data 
validation, engineering analysis, regulatory 
accounting, or grid performance evaluation, 
including experience with relevant modeling 
tools and with data systems of the Commission 
or the Department of Energy;
(ii) possess or otherwise have access to 
technical and analytical expertise appropriate 
to the metrics being verified, including in 
engineering, economics, data analytics, or 
regulatory accounting; and
(iii) be independent from the entity being 
verified and have no financial, contractual, or 
governance conflicts of interest, including 
having no affiliation or common ownership with 
any entity responsible for managing or 
overseeing the pension or benefit funds of a 
reporting entity;
(B) procedures for auditing the assumptions and 
methodologies used in applying performance metrics, 
including to detect selective reporting and ensure 
alignment with Commission-defined protocols;
(C) requirements to ensure that any single 
independent evaluator, or their parent company or 
subsidiary--
(i) may not evaluate a reporting entity 
that is a covered transmission owner more than 
5 reporting periods in a row, or more than 15 
times in any 10-year period; and
(ii) may not evaluate a reporting entity 
that is an ISO, RTO, or transmission planning 
entity more than 3 reporting periods in a row, 
or more than 7 times in any 10-year period;
(D) requirements under which an independent 
evaluator approved by the Commission may verify the 
information in the scorecard of the reporting entity, 
by reviewing supporting documentation, conducting 
project inspections, and applying standardized 
evaluation, measurement, and verification protocols for 
the metrics included in the scorecard;
(E) requirements for public disclosure of the 
results of such verification, including any adjustments 
to reported values, methodologies used in the 
verification process, and justifications for material 
discrepancies; and
(F) a process for reviewing and refining 
verification protocols at regular intervals, not less 
frequently than once every 3 years, in consultation 
with any relevant stakeholder advisory group convened 
under section 5, to incorporate advances in data 
analytics, energy system modeling, and grid performance 
assessment.
(2) Role of national laboratories.--In carrying out this 
subsection, the Commission shall--
(A) collaborate with National Laboratories that 
have the necessary expertise, in coordination with the 
Secretary, to design and publish standardized 
verification protocols, including templates, analytical 
tools, and calibration datasets;
(B) utilize the technical expertise of National 
Laboratories to assist in the training, evaluation, or 
approval of independent evaluators;
(C) engage National Laboratories in conducting 
selective audits or quality assurance reviews of 
verified scorecards during initial implementation of 
the scorecard reporting and verification process and 
implementation of any subsequent updates to such 
scorecards; and
(D) consult National Laboratories during periodic 
updates to the verification process, in coordination 
with any relevant stakeholder advisory group convened 
under section 5.
(d) Independent Audits.--
(1) In general.--The Commission, in consultation with the 
Secretary, shall designate National Laboratories with necessary 
expertise, or other qualified institutions, to conduct 
independent audits of scorecards published under subsection (a) 
on a periodic or as-needed basis to ensure the accuracy, 
completeness, and integrity of reported data, methodologies, 
and performance metrics.
(2) Initiation.--An audit under this subsection may be 
initiated--
(A) at the discretion of the Secretary;
(B) upon identification of material discrepancies 
in reported metrics;
(C) in response to concerns raised by a stakeholder 
advisory group convened under section 5; or
(D) as part of a randomized, rotating sample of 
reporting entities to support continuous oversight.
(3) Results.--The results of an audit conducted under this 
subsection shall be made publicly available not later than 2 
months after completion of the audit.
(e) Rulemaking.--
(1) In general.--Not later than 1 year after the date of 
enactment of this Act, the Commission shall issue a final rule 
to carry out this section.
(2) Department of energy support.--The Secretary shall 
provide technical assistance, subject-matter expertise, and 
access to relevant data and tools to the Commission in 
developing the rule required to be published under this 
subsection.
(3) Inclusions.--The Commission shall include in the rule 
issued under this section--
(A) requirements to ensure timely and consistent 
reporting, which may include requirements for data-
sharing agreements, protocols for data access, and 
other mechanisms as necessary to facilitate the 
completion of scorecards;
(B) allowance for the use of proxies, estimates, or 
approximations only--
(i) where direct data are unavailable; and
(ii) if the proxies, estimates, or 
approximations are based on the best available 
data, transparently documented, subject to 
Commission review and approval, and updated as 
improved data become available; and
(C) requirements that all reported metrics reflect 
a good-faith effort to provide accurate representations 
of transmission facility and system performance, 
subject to Commission review and oversight.
(4) Revisions.--In issuing any revisions to the rule under 
this section, the Commission shall ensure that--
(A) such revisions are based on the outcomes of any 
applicable technical conference held under section 5;
(B) the period for public comment on such revisions 
is not less than 90 days; and
(C) the final rule making such revisions is issued 
not later than 180 days after the close of such period 
for public comment.
(f) Enforcement.--With respect to any Independent System Operator, 
Regional Transmission Organization, or covered transmission owner 
subject to the requirements of part II of the Federal Power Act that is 
required to publish a scorecard under subsection (a), a violation of a 
requirement of this section shall be considered a violation of a 
provision of such part II for purposes of section 316A of such Act (16 
U.S.C. 825o-1).
(g) Report.--The Secretary shall annually publish a report that 
compiles and analyzes scorecards submitted to the Secretary under 
subsection (a) and, for each metric--
(1) ranks the performance of reporting entities, grouped by 
market type and governance structure; and
(2) explains the metric and describes any changes over time 
in the affordability, reliability, equity, or environmental 
performance of the transmission system, as evidenced by changes 
in the information included by reporting entities in such 
scorecards with respect to the metric.
(h) Scorecard Review.--Not later than 3 years after the date of 
enactment of this Act, and every 3 years thereafter, the Secretary, in 
coordination with the Commission, shall conduct a comprehensive review 
of the implementation of this section, including the administration of 
the section, data collection and coordination, reporting entity 
compliance, stakeholder engagement, and the effectiveness of the 
information included in scorecards as a policy tool and issue a public 
report that includes--
(1) an assessment and comparison of the changes over time 
in utility performance regarding the metrics required to be 
included in the scorecards;
(2) evaluation of data quality, availability, 
methodologies, and verification practices relevant to the 
scorecards; and
(3) findings and recommendations regarding the scorecards 
provided by the technical conferences held and stakeholder 
advisory group convened under section 5.

SEC. 4. ACCESSIBILITY AND PUBLIC TRANSPARENCY.

(a) Establishment of Public-Facing Scorecard Portal.--
(1) Initiation.--Not later than 12 months after the date of 
enactment of this Act, the Secretary, in collaboration with the 
Commission and the Administrator, shall initiate the 
establishment of a public, searchable online portal housing 
scorecards and underlying data submitted to the Secretary under 
this Act.
(2) Portal availability.--Not later than 18 months after 
the date of enactment of this Act, the Secretary shall 
establish and make available a public, searchable online portal 
housing scorecards and underlying data submitted to the 
Secretary under this Act.
(b) Inclusion in Portal.--The Secretary shall make public through 
the searchable online portal established under this section each 
scorecard, together with the underlying data associated with each 
scorecard, that is submitted to the Secretary under this Act.

SEC. 5. SCORECARD IMPROVEMENT.

(a) Technical Conferences.--The Commission shall hold public 
technical conferences not less often than once every 3 years to solicit 
stakeholder feedback on--
(1) the effectiveness of scorecard metrics in conveying the 
performance of a given reporting entity;
(2) the sufficiency and quality of the data disclosed in 
scorecards;
(3) the alignment of scorecards with Federal and State 
priorities, including affordability, reliability, and 
congestion reduction of transmitted electricity; and
(4) opportunities to refine metrics in light of emerging 
technologies, grid conditions, and energy markets.
(b) Stakeholder Advisory Groups.--For purposes of a rulemaking 
under section 3 and each technical conference held under subsection 
(a), the Commission shall convene a stakeholder advisory group to 
provide advice to the Commission. Each such stakeholder advisory group 
shall be composed of 17 members, as follows:
(1) 2 members representing State public utility 
commissions.
(2) 2 members representing covered transmission owners.
(3) 2 members representing independent power producers.
(4) 2 members representing Regional Transmission 
Organizations and Independent System Operators.
(5) 1 member representing the Electric Reliability 
Organization.
(6) 2 members representing transmission planning entities.
(7) 2 members representing ratepayer advocacy 
organizations, each of whom shall be employed by, or formally 
designated by, an organization the primary mission of which is 
the representation of residential, commercial, or industrial 
ratepayers in regulatory or ratemaking proceedings before State 
or Federal authorities.
(8) 2 members with expertise in energy data systems, grid 
modeling, or electricity market analytics, each of whom shall 
possess significant professional experience or academic 
qualifications, representing industry, independent analytics 
firms, or academic or research institutions, including the 
National Laboratories.
(9) 2 members with expertise in energy systems performance, 
representing academic or research institutions, including the 
National Laboratories.
(c) Response Required.--Not later than 60 days after receiving any 
advice from a stakeholder group convened under subsection (b), the 
Commission shall respond in writing to such advice.

SEC. 6. DEFINITIONS.

In this Act:
(1) Administrator.--The term ``Administrator'' means the 
Administrator of the Energy Information Administration of the 
Department of Energy.
(2) Commission.--The term ``Commission'' means the Federal 
Energy Regulatory Commission.
(3) Covered transmission owner.--The term ``covered 
transmission owner'' means any entity, other than an 
Independent System Operator, Regional Transmission 
Organization, or transmission planning entity, that--
(A) owns, operates, or controls transmission 
facilities that are part of, or connected to the bulk-
power system;
(B) provides, or is capable of providing, 
transmission service for the movement of electric 
energy, whether in interstate or intrastate commerce; 
and
(C) if the entity owns, operates, or controls 
transmission facilities that are not part of, or 
connected to, the bulk-power system, the total 
transmission capacity under peak demand conditions of 
all transmission facilities owned, operated, or 
controlled by the entity is 100 megawatts or greater.
(4) Federal power act terms.--
(A) Bulk-power system; ero.--The terms ``bulk-power 
system'' and ``Electric Reliability Organization'' have 
the meanings given those terms in section 215 of the 
Federal Power Act (16 U.S.C. 824o).
(B) ISO; rto; transmitting utility.--The terms 
``Independent System Operator'', ``ISO'', ``Regional 
Transmission Organization'', ``RTO'', and 
``transmitting utility'' have the meanings given those 
terms in section 3 of the Federal Power Act (16 U.S.C. 
796).
(5) Grid-enhancing technology.--The term ``grid-enhancing 
technology'' means any technology the Commission determines 
materially improves transfer capacity or interconnection 
efficiency, or reduces technical losses, without relying on 
traditional wires-based transmission expansion, which shall 
include--
(A) dynamic line rating systems;
(B) advanced power flow control devices;
(C) topology optimization tools and software-based 
reconfiguration technologies;
(D) real-time monitoring and sensing equipment that 
improves line utilization or visibility; and
(E) transformer upgrades, advanced transmission 
technologies, or reactive power equipment.
(6) Interregional interconnection.--The term 
``interregional interconnection'' means a transmission facility 
or interconnection project that enables the transfer of 
electric energy between two or more transmission planning 
regions, including connections between any of the Western 
Interconnection, the Eastern Interconnection, and the Electric 
Reliability Council of Texas.
(7) Reporting entity.--The term ``reporting entity'' means 
an entity required to submit a scorecard under this Act.
(8) Scorecard.--The term ``scorecard'' means a report 
required to be submitted by a covered transmission owner, 
Independent System Operator, Regional Transmission 
Organization, or transmission planning entity pursuant to 
section 3.
(9) Seam.--The term ``seam'' means a boundary or interface 
between neighboring transmission systems or grid operators.
(10) Secretary.--The term ``Secretary'' means the Secretary 
of Energy.
(11) Transmission planning entity.--The term ``transmission 
planning entity'' means an entity, other than a RTO or an ISO, 
that is responsible for planning for the deployment of electric 
transmission for a transmission planning region.
(12) Transmission planning region.--The term ``transmission 
planning region'' means a geographic area determined by the 
Commission to satisfy the requirements for the scope of 
regional transmission planning, as established in or in 
compliance with the following orders issued by the Commission:
(A) ``Transmission Planning and Cost Allocation by 
Transmission Owning and Operating Public Utilities'' 
published in the Federal Register on October 24, 2012 
(77 Fed. Reg. 64890).
(B) ``Building for the Future Through Electric 
Regional Transmission Planning and Cost Allocation'' 
published in the Federal Register on June 11, 2024 (89 
Fed. Reg. 49280).
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