No official summary available for this bill.
[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).
<all>
Introduced in House
Introduced in House
Referred to the House Committee on Energy and Commerce.
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