117 HR 5154 IH: Connecting Hard-to-reach Areas with Renewably Generated Energy Act of 2023
U.S. House of Representatives
2023-08-04
text/xml
EN
Pursuant to Title 17 Section 105 of the United States Code, this file is not subject to copyright protection and is in the public domain.
I
118th CONGRESS
1st Session
H. R. 5154
IN THE HOUSE OF REPRESENTATIVES
August 4, 2023
Ms. Ocasio-Cortez (for herself, Mr. Casar, Mr. Levin, Mr. Tonko, Mr. Bowman, Mr. Huffman, Ms. Norton, Ms. Tlaib, Mr. Espaillat, Mr. Frost, Ms. Schakowsky, Mr. Vargas, Ms. Castor of Florida, Ms. Jayapal, Mr. Cleaver, Mr. Robert Garcia of California, Mr. Blumenauer, Ms. Omar, Mr. Grijalva, Ms. Pressley, Ms. Balint, Mr. Goldman of New York, Ms. Barragán, Mr. Jackson of Illinois, Ms. Crockett, Mr. Johnson of Georgia, Mrs. Foushee, and Ms. Lofgren) introduced the following bill; which was referred to the Committee on Energy and Commerce
A BILL
To require the Federal Energy Regulatory Commission to promulgate regulations with respect to regional and interregional transmission planning, and for other purposes.
1.

Short title
This Act may be cited as the “Connecting Hard-to-reach Areas with Renewably Generated Energy Act of 2023” or the “CHARGE Act of 2023”.
2.

Findings
Congress finds that—
(1)
current transmission planning is fractured across many jurisdictions, prioritizes incumbent entities and highly localized transmission, and fails to identify cost-effective solutions for 21st century needs;
(2)
the historical structure, regulations, and incentives of the electric power system lead to under-planning and under-investment in the regional and interregional transmission lines that are needed for a reliable and resilient grid;
(3)
much of the existing transmission infrastructure of the United States is in need of significant upgrade or replacement;
(4)
the energy sector of the United States is at a critical juncture, with a rapidly changing power generation mix and new public policy mandates;
(5)
it is imperative to proactively plan for electricity transmission in the future, including by taking into account long-term changes to demand and load growth;
(6)
renewable energy resources must be incorporated into the grid efficiently in order to meet State and Federal decarbonization goals;
(7)
the public desires, and has a right to, electricity data that are transparent, organized, and accessible;
(8)
having reliable and diverse sources of electricity generation is a foundational need for the entire economy;
(9)
climate change has increased the frequency and intensity of severe weather events that affect the grid;
(10)
it is in the national interest to implement policies that provide effective electric infrastructure to save consumers money, avoid preventable damage, ensure energy reliability, and save lives;
(11)
the Federal Government has a responsibility to combat rising transmission costs and ensure customers receive just and reasonable rates for electricity;
(12)
industry experience, scientific studies, and modern examples of reformed electricity transmission provide confidence that new public policies and regulatory guidance will achieve more efficient and beneficial planning than the status quo; and
(13)
there is increasing opportunity for public, Tribal, or rural cooperative development of transmission due to the recently established direct-pay incentives under section 6417 of the Internal Revenue Code of 1986, enacted by section 13801 of Public Law 117–169 (commonly known as the “Inflation Reduction Act of 2022”) (136 Stat. 2003).
3.

Definitions
In this Act:
(1)

Commission
The term Commission means the Federal Energy Regulatory Commission.
(2)

Independent System Operator
The term Independent System Operator has the meaning given the term in section 3 of the Federal Power Act (16 U.S.C. 796).
(3)

Interconnection customer
The term interconnection customer means an individual or entity that has submitted to the owner or operator of a transmission facility or transmission system a request to interconnect a generation project or energy storage project that is subject to the jurisdiction of the Commission.
(4)

Interregional transmission planning process
The term interregional transmission planning process means a joint process by transmission providers in 2 or more adjacent transmission planning regions to evaluate electric energy transmission needs.
(5)

Load-serving entity
The term load-serving entity has the meaning given the term in section 217(a) of the Federal Power Act (16 U.S.C. 824q(a)).
(6)

Regional Transmission Organization
The term Regional Transmission Organization has the meaning given the term in section 3 of the Federal Power Act (16 U.S.C. 796).
(7)

Transmission facility
The term transmission facility means a facility that is used for the transmission of electric energy in interstate commerce.
(8)

Transmission planning region
The term transmission planning region means a region for which electric energy transmission planning is appropriate, as determined by the Commission, such as a region established pursuant to the guidance contained in the final rule of the Commission entitled “Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities” (76 Fed. Reg. 49842 (August 11, 2011)).
(9)

Transmission provider
The term transmission provider means a public utility (as defined in section 201(e) of the Federal Power Act (16 U.S.C. 824(e))) that owns, operates, or controls 1 or more transmission facilities.
4.

Transmission planning and cost allocation
(a)

Rulemaking
Not later than 18 months after the date of enactment of this Act, the Commission shall promulgate a final rule that—
(1)
establishes transmission planning processes and cost-allocation processes that—
(A)
ensure that transmission providers—
(i)
engage in interregional transmission planning processes and interconnection-wide transmission planning processes, in conjunction with transmission planning processes within transmission planning regions;
(ii)
harmonize interregional transmission planning processes and interconnection-wide transmission planning processes with other regional transmission planning processes, such as by using a joint model on a consistent timeline with a unified set of minimum requirements regarding needs, input assumptions, and benefit metrics;
(iii)
include as part of planning and cost-allocation processes the use of grid-enhancing transmission technologies and alternative transmission technologies that increase delivery of power over transmission networks, including, at a minimum—
(I)
dynamic line ratings;
(II)
topology optimization;
(III)
power flow control;
(IV)
advanced conductors and superconductors; and
(V)
storage-as-transmission;
(iv)
conduct interregional and interconnection-wide planning regularly and not less frequently than once every 5 years;
(v)
conduct interregional and interconnection-wide planning based on a range of possible future load and generation scenarios; and
(vi)
are required to incorporate in a transmission planning process the full scope of benefits of transmission investment, including, at a minimum—
(I)
reduced costs of electric energy to customers, including reduced costs associated with lower quantities of necessary capacity, ancillary services, and reserve margins;
(II)
access to resources in neighboring transmission planning regions;
(III)
the transmission of renewable energy or the ability of renewable energy to connect to the grid;
(IV)
improvements in reliability, resilience, and flexibility of the grid, including, at a minimum—
- (aa)
reduced loss of load probability;
- (bb)
increased resource diversity;
- (cc)
increased climate hardening; and
- (dd)
increased ability to maintain functionality during regionally appropriate weather conditions and severe weather scenarios;
(V)
leveraging resources across climatological patterns or time zones to account for resource availability and weather patterns;
(VI)
avoidance, to the maximum extent practicable, of sensitive environmental areas and cultural heritage sites;
(VII)
reasonable and economical use of existing rights-of-way;
(VIII)
market facilitation benefits, including, at a minimum, increased competitiveness, liquidity, and integrity of broader geographic markets;
(IX)
avoided costs and deferred cost savings, including reduced generation costs and reduced future transmission investment costs;
(X)
the integration of grid-enhancing technologies;
(XI)
meeting local, State, and Federal policy goals, including goals established in decarbonization, climate, and clean energy laws (including regulations);
(XII)
protections to maintain just and reasonable rates for customers; and
(XIII)
any other production costs savings or other economic benefits from proposed transmission projects;
(B)
require that regional and interregional cost-allocation methodologies allocate costs on the basis of the multiple benefits described in subclauses (I) through (XIII) of subparagraph (A)(vi);
(C)
incorporate a 10- to 20-year future resource mix for each load-serving entity and State;
(D)
ensure that local or regional transmission planning processes do not impair interregional and interconnection-wide transmission planning processes;
(E)
require transmission providers to maximize the use of portfolio-based cost allocations;
(F)
in cases in which costs and benefits are difficult to quantify, may allocate transmission investment costs among transmission system customers in proportion to—
(i)
in the case of regional projects, the share of electricity of each customer in the region; or
(ii)
in the case of interregional projects, the share of electricity of each customer in each applicable region; and
(G)
to the extent practicable, prevent transmission providers from using cost-allocation methodologies that—
(i)
discourage distributed generation, energy efficiency, demand response, or storage if more economic than transmission;
(ii)
are constrained by consideration only of benefits that are easy to allocate; or
(iii)
undermine previous cost-allocation agreements for projects already in operation; and
(2)
allows a transmission developer of an interregional transmission project to submit to the Commission a request to recover all or a portion of the costs of the project under section 205 of the Federal Power Act (16 U.S.C. 824d) if—
(A)
the project is selected through a transmission planning process that meets the criteria described in paragraph (1), in accordance with the transmission planning processes and cost-allocation processes established under that paragraph; or
(B)
the transmission developer demonstrates to the satisfaction of the Commission that—
(i)
the project connects more than 1 transmission planning region; and
(ii)
the benefits of the project substantially outweigh the costs of the project after accounting for any transmission projects developed pursuant to a transmission planning process that meets the criteria described in paragraph (1).
(b)

Cost recovery and allocation requirements
(1)

Cost-benefit analysis
In making a determination under subsection (a)(2)(B)(ii) of whether a transmission developer has demonstrated to the satisfaction of the Commission that the benefits of a project substantially outweigh the costs of the project, the Commission shall consider the benefits described in subsection (a)(1)(A)(vi).
(2)

Allocation
For transmission projects that meet the criteria of subparagraph (A) or (B) of subsection (a)(2), the Commission shall allocate the costs of those transmission projects to customers in the applicable regions that benefit from those projects—
(A)
using the benefits described in subsection (a)(1)(A)(vi); or
(B)
in cases in which those benefits are difficult to quantify, using the cost allocation methodology described in subsection (a)(1)(F).
(3)

Savings provision
Nothing in this section limits, or may be construed to limit, any rights of transmission developers to submit and have rates approved by the Commission pursuant to section 205 of the Federal Power Act (16 U.S.C. 824d).
(c)

Availability of resource plans
The Commission may require a load-serving entity to make publicly available any applicable resource plans, including any plans relating to the requirement described in subsection (a)(1)(C), if, in the determination of the Commission, the plans are not adequately described in publicly stated plans in Securities and Exchange Commission filings, State agency filings, and power purchase contracts.
(d)

Technical conferences
(1)

In general
As part of the rulemaking process under subsection (a), the Commission may convene a technical conference to consider implementation details, as the Commission determines to be appropriate.
(2)

Participation
(A)

Leadership
A technical conference convened under paragraph (1) may be led by the members of the Commission, subject to subparagraph (B).
(B)

Required invitations
On election under subparagraph (A) by members of the Commission to lead a technical conference, the Commission shall invite to participate in the technical conference representatives of residential ratepayers, transmission providers, environmental justice and equity groups, Tribal communities, Independent System Operators, Regional Transmission Organizations, consumer protection groups, renewable energy advocates, State utility commission and energy offices, and such other entities as the Commission determines to be appropriate.
(C)

Timeline
The Commission may establish and enforce a timeline for a technical conference convened under paragraph (1) that discourages actions by participants that may unnecessarily delay the conference.
(3)

Public comment
The Commission may provide an opportunity for public comment on the topics considered by a technical conference convened under paragraph (1).
(e)

Office of Public Participation
The Commission shall consult the Office of Public Participation during the rulemaking process under subsection (a), including with respect to—
(1)
guidance on public participation requirements;
(2)
communications with the public concerning transmission planning that may impact local communities and landowners, including Tribal, indigenous, and environmental justice communities; and
(3)
minimum data transparency and access requirements.
(f)

Joint Federal-State Task Force on Electric Transmission
The Commission may consult the Joint Federal-State Task Force on Electric Transmission in any actions that—
(1)
involve shared Federal and State regulatory authority and processes; or
(2)
would benefit from a combined Federal and State perspective.
5.

Interregional minimum transfer requirements
(a)

Electric reliability
Section 215(i)(2) of the Federal Power Act (16 U.S.C. 824o(i)(2)) is amended by striking “or transmission”.
(b)

Rulemaking
(1)

In general
Not later than 18 months after the date of enactment of this Act, the Commission shall promulgate a final rule that establishes a minimum transfer capability that—
(A)
shall govern minimum transfer requirements between transmission planning regions;
(B)
achieves reliability and resilience standards during plausible extreme weather scenarios;
(C)
optimizes efficiency of delivering renewable energy to demand centers; and
(D)
incorporates the best available science relating to energy transmission, climatological patterns, climate change causes and impacts, grid reliability, and grid resiliency, including study results from the Department of Energy or National Laboratories (as defined in section 2 of the Energy Policy Act of 2005 (42 U.S.C. 15801)).
(2)

Rates
All rates associated with transmission facilities developed pursuant to the rule promulgated under paragraph (1) shall be subject to the requirements of sections 205 and 206 of the Federal Power Act (16 U.S.C. 824d, 824e) that all rates, charges, terms, and conditions—
(A)
shall be just and reasonable; and
(B)
shall not be unduly discriminatory or preferential.
6.

Data transparency
Part II of the Federal Power Act (16 U.S.C. 824 et seq.) is amended by adding at the end the following:
“224.

Data transparency
(a)

Data
The Commission shall require all public utilities and other entities subject to the jurisdiction of the Commission to make, through coordination with the Environmental Protection Agency and an online database operated by the Administrator of the Energy Information Administration, hourly operating data transparent and accessible to the public, including original source data that—
(1)
are organized and easy to understand;
(2)
are centralized and provided in usable formats, including an application programming interface;
(3)
are available free of charge;
(4)
are published as close to real-time as is practicable;
(5)
include generation by fuel type;
(6)
include hourly marginal greenhouse gas emissions per megawatt-hour of electricity generated within the metered boundaries of each entity and for each specific electrical bus location on the grid where an injection or withdrawal of power is modeled (commonly known as a pricing node), subject to the condition that the marginal greenhouse gas emissions data made available pursuant to this paragraph shall be measured in the same time interval by which locational marginal price is measured at the same location, but in no case shall the interval by which marginal greenhouse gas emissions are measured for purposes of this paragraph be greater than hourly;
(7)
include congestion cost and the limiting elements that cause the congestion; and
(8)
include hourly locational data on generation curtailment and the reasons for that curtailment.
(b)

Commercial products
The Commission may identify and reduce regulatory barriers to the development of commercial products that use the data made publicly available under subsection (a) in order to provide verifiable emissions reductions, including short- and long-term nodal congestion products.
(c)

Appropriation
In addition to amounts otherwise made available to the Administrator of the Energy Information Administration, there is appropriated to the Administrator of the Energy Information Administration for fiscal year 2024, out of any funds in the Treasury not otherwise appropriated, $10,000,000 to develop and operate the database described in subsection (a), to remain available until expended.”.
7.

Study on methods of electricity procurement and development
(a)

In general
Not later than 1 year after the date of enactment of this Act, the National Academies of Sciences, Engineering, and Medicine, in coordination with the Commission and the Department of Energy, shall conduct, and submit to the Committee on Energy and Natural Resources of the Senate and the Committee on Energy and Commerce of the House of Representatives and make available on a public website a report describing the results of, a study that identifies the potential benefits and other effects to consumers from—
(1)
procuring generation from independent entities that are not utilities through a competitive process administered by—
(A)
an Independent System Operator or a Regional Transmission Organization; or
(B)
another independent entity; and
(2)
generation and transmission that is financed, developed, or owned by—
(A)
an entity described in subsection (b);
(B)
any corporation that is wholly owned, directly or indirectly, by 1 or more entities described in that subsection; or
(C)
cooperatives that furnish electricity to rural areas.
(b)

Entity described
An entity referred to in subsection (a)(2)(A) is—
(1)
the United States;
(2)
a State;
(3)
the District of Columbia;
(4)
the Commonwealth of Puerto Rico;
(5)
any other territory or possession of the United States;
(6)
any political subdivision of an entity described in any of paragraphs (2) through (5);
(7)
a Tribal government; or
(8)
any agency, authority, or instrumentality of any 1 or more entities described in paragraphs (1) through (7).
(c)

Considerations
The study conducted under subsection (a) shall—
(1)
take into consideration, at a minimum, potential benefits with respect to—
(A)
cost savings;
(B)
improved grid reliability and resilience; and
(C)
greenhouse gas reductions;
(2)
compare the potential benefits identified under paragraph (1) to the circumstances of consumers whose generation is not procured through a competitive process; and
(3)
compare the potential benefits and effects identified under subsection (a)(2) to the circumstances of consumers whose generation and transmission is not financed and developed, directly or indirectly, by a public entity.
(d)

Authorization of appropriations
There is authorized to be appropriated to carry out this section $5,000,000 for fiscal year 2024.
8.

State subsidies
Part II of the Federal Power Act (16 U.S.C. 824 et seq.) (as amended by section 6) is amended by adding at the end the following:
“225.

State subsidies
In order to promote competition in wholesale markets, reliability, and affordability, the Commission shall not use offer-price mitigation methods to counteract the effects of State subsidies for renewable energy resources.”.
9.

Office of Transmission
Part III of the Federal Power Act is amended by inserting after section 317 (16 U.S.C. 825p) the following:
“318.

Office of Transmission
(a)

Establishment
There shall be established in the Commission an office, to be known as the “Office of Transmission” (referred to in this section as the Office).
(b)

Director
The Office shall be administered by a Director, who shall be appointed by the Chairman of the Commission.
(c)

Duties
The Director of the Office shall—
(1)
review transmission plans submitted by public utilities in accordance with the regional and interregional transmission planning processes, including the processes established pursuant to section 206;
(2)
coordinate transmission-related matters of the Commission, as the Commission determines to be appropriate;
(3)
carry out the responsibilities of the Commission under section 216, in coordination with the Office of Energy Projects of the Commission;
(4)
review opportunities for innovation in transmission planning and operation, including deployment of grid-enhancing technologies, advanced conductors, and other approaches; and
(5)
provide oversight of transmission planning activities subject to the jurisdiction of the Commission.”.
10.

Interconnection
Not later than 1 year after the date of enactment of this Act, the Commission shall promulgate regulations, or revise existing regulations—
(1)
to prohibit a public utility from requiring an interconnection customer to exclusively or disproportionately fund, without reimbursement, the costs of any network upgrade identified as necessary for the interconnect request of the interconnection customer;
(2)
to encourage cost-sharing models that reflect the broad set of benefits and beneficiaries for any network upgrades identified as needed in an interconnection or affected system study, subject to the requirement that the model adheres to any requirements established under paragraph (1); and
(3)
to alleviate interconnection backlogs and reduce informational and procedural barriers in interconnection, which may include—
(A)
the establishment of an interconnection analysis center within the Office of Transmission established under section 318 of the Federal Power Act; and
(B)
consultation with staff and the use of other resources of the Department of Energy.
11.

Independent transmission monitor
(a)

In general
Not later than 1 year after the date of enactment of this Act, for the purpose of monitoring the planning and operation of transmission facilities in transmission planning regions, the Commission shall—
(1)
(A)
require each transmission planning region to establish an independent entity to monitor the planning and operation of transmission facilities in the transmission planning region; and
(B)
establish a council, to be known as the “Council of Transmission Monitors”—
(i)
to provide oversight of each independent entity established pursuant to subparagraph (A); and
(ii)
to ensure interregional collaboration and consistency; or
(2)
establish an independent entity to monitor the planning and operation of transmission facilities in all transmission planning regions.
(b)

Role of transmission monitor
An independent entity described in paragraph (1)(A) or (2) of subsection (a) shall, as applicable—
(1)
review the operation of applicable transmission planning regions for inefficiency and practices that may lead to unjust and unreasonable rates;
(2)
review costs of transmission facilities, including identifying inefficiencies among local, regional, and interregional planning;
(3)
provide examples and advice to transmission providers on appropriate regional transmission operations, planning, and cost-allocation processes; and
(4)
identify situations in which—
(A)
nonwire alternatives may be more cost-effective than transmission;
(B)
grid-enhancing technologies may be appropriate;
(C)
high-capacity, interregional lines may be—
(i)
more cost-effective; or
(ii)
a more appropriate reliability and resilience alternative; or
(D)
high-capacity regional lines may be more cost-effective than local upgrades.
12.

Advisory committee
(a)

In general
Not later than 1 year after the date of enactment of this Act, the Commission shall establish an advisory committee (referred to in this section as the committee) to make recommendations regarding—
(1)
oversight and governance of Independent System Operators or Regional Transmission Organizations;
(2)
stakeholder participation best practices—
(A)
that ensure transparency, accountability, independence, oversight, and fair representation;
(B)
the purposes of which are to promote competition, reliability, and affordability in all transmission planning regions; and
(C)
that include best practices relating to stakeholder disclosure of the impact of a proposed tariff reform on the company or client of the stakeholder prior to voting on the proposed tariff reform;
(3)
enhancing transparency and open decisionmaking in regions not classified as Independent System Operators or Regional Transmission Organizations; and
(4)
the requirements of governing boards within Independent System Operators or Regional Transmission Organizations.
(b)

Representation
The committee shall be composed of not more than 30 members, including—
(1)
at least 2 representatives of end-use customers;
(2)
at least 1 representative of transmission providers;
(3)
at least 2 representatives of environmental justice and equity groups;
(4)
at least 1 representative of Tribal communities;
(5)
at least 1 representative of Independent System Operators;
(6)
at least 1 representative of Regional Transmission Organizations;
(7)
at least 1 representative of consumer protection groups;
(8)
at least 2 representatives of renewable energy advocates;
(9)
at least 1 representative of State commissions;
(10)
at least 1 representative of public power entities;
(11)
at least 1 representative of marketers; and
(12)
at least 1 representative of generators.
(c)

FACA applicability
Chapter 10 of title 5, United States Code (commonly referred to as the “Federal Advisory Committee Act”), shall apply to the committee.
13.

RTO and ISO Governance
(a)

Stakeholder processes
(1)

Public voting
Each vote cast by any party during a stakeholder process of a Regional Transmission Organization or Independent System Operator shall be made public.
(2)

Public participation funding
Not later than 180 days after the date of enactment of this Act, the Commission shall promulgate regulations requiring Regional Transmission Organizations and Independent System Operators to develop a process to provide intervenor compensation or other funding to assist with public interest participation in the stakeholder processes of the Regional Transmission Organization or Independent System Operator.
(3)

Consumer organizations; membership fee waivers
Not later than 18 months after the date of enactment of this Act, the Commission shall promulgate regulations requiring each Regional Transmission Organization and Independent System Operator—
(A)
to grant full voting and participation rights for consumer organizations within stakeholder processes; and
(B)
to consider membership fee waivers for stakeholder processes.
(b)

Stakeholder meetings
(1)

Recording and transcription
Each stakeholder meeting of a Regional Transmission Organization or Independent System Operator shall be recorded and transcribed, and the recording and transcription shall be made freely available to the public.
(2)

Disclosure requirement
(A)

In general
An individual described in subparagraph (B) shall publicly disclose, at any stakeholder meeting of a Regional Transmission Organization or Independent System Operator that the individual attends or in which the individual otherwise participates—
(i)
that the individual is attending or participating on behalf of a Regional Transmission Organization or Independent System Operator; and
(ii)
the identity of that Regional Transmission Organization or Independent System Operator.
(B)

Individual described
An individual referred to in subparagraph (A) is any representative of a law firm or consulting firm, or any other agent, that is compensated to represent or advocate for the interests of a Regional Transmission Organization or Independent System Operator.
(c)

Applicability of FOIA
Section 552 of title 5, United States Code (commonly known as the “Freedom of Information Act”), including any exceptions under that section, shall apply to the activities, records, and proceedings of each Regional Transmission Organization and Independent System Operator, including with respect to the operations of the Regional Transmission Organization or Independent System Operator.
(d)

Limitations on sponsorships
Not later than 180 days after the date of enactment of this Act, the Commission shall promulgate regulations—
(1)
to prohibit entities with interests in matters before a Regional Transmission Organization or Independent System Operator from serving as financial sponsors of special events or activities at Regional Transmission Organization or Independent System Operator meetings; or
(2)
if the Commission determines appropriate, to establish disclosure requirements for entities with interests in matters before a Regional Transmission Organization or Independent System Operator that serve as financial sponsors of special events or activities at Regional Transmission Organization or Independent System Operator meetings.
(e)

Boards of directors
(1)

Independent board
Not later than 180 days after the date of enactment of this Act, the Commission shall promulgate regulations requiring, subject to exceptions defined by the Commission, that the board of directors of a Regional Transmission Organization or Independent System Operator be independent from, and not affiliated with, the members of the Regional Transmission Organization or Independent System Operator.
(2)

Membership
Not later than 18 months after the date of enactment of this Act, the Commission shall promulgate regulations—
(A)
requiring the board of directors of each Regional Transmission Organization and Independent System Operator to have members who have expertise and experience in representing consumers, including at least 1 member with expertise in the interests of retail residential consumers;
(B)
establishing the number of members described in subparagraph (A) that shall be required on a board of directors described in that subparagraph in order to avoid marginalization of the perspectives and contributions of those members; and
(C)
requiring each Regional Transmission Organization and Independent System Operator to designate at least 1 member of the board of directors of that Regional Transmission Organization or Independent System Operator who shall represent and be directly accountable, in such manner as the Commission determines to be appropriate, to the public interest within the geographic footprint of the Regional Transmission Organization or Independent System Operator.
(f)

Employment and compensation
(1)

Revolving door prohibitions
(A)

In general
Not later than 180 days after the date of enactment of this Act, the Commission shall promulgate regulations requiring Regional Transmission Organizations and Independent System Operators to establish rules prohibiting the Regional Transmission Organization or Independent System Operator from employing, during the periods described in subparagraph (B), an individual who is or was an executive of a utility (commonly known as a “revolving door prohibition”).
(B)

Periods described
The periods referred to in subparagraph (A) are—
(i)
any period during which the individual is an executive of a utility; and
(ii)
the 1-year period beginning on the date on which the employment of the individual as an executive of a utility ends.
(2)

Compensation
Not later than 180 days after the date of enactment of this Act, the Commission shall establish guidelines for executive compensation at Regional Transmission Organizations and Independent System Operators in order to limit excessive compensation of those executives.
(g)

Enforcement
The Commission shall enforce the requirements of this section using the authority of the Commission under sections 205 and 206 of the Federal Power Act (16 U.S.C. 824d, 824e).
14.

Intervenor funding at Office of Public Participation
(a)

In general
Section 319(b)(2) of the Federal Power Act (16 U.S.C. 825q–l(b)(2)) is amended—
(1)
in subparagraph (A), by striking the comma and inserting a semicolon;
(2)
by redesignating subparagraphs (A) and (B) as clauses (i) and (ii), respectively, and indenting the clauses appropriately;
(3)
in the matter preceding clause (i) (as so redesignated), in the second sentence, by striking “Such compensation” and inserting the following:
“(B)

Determinations required
Compensation under this paragraph”; and
(4)
by striking the paragraph designation and all that follows through “by it,” in the matter preceding subparagraph (B) (as so designated) and inserting the following:
“(2)

Compensation
(A)

In general
On making the determinations described in subparagraph (B) and in accordance with rules promulgated by the Commission, the Commission shall”.
(b)

Rulemaking
Not later than 1 year after the date of enactment of this Act, the Commission shall promulgate a final rule to provide compensation under paragraph (2) of section 319(b) of the Federal Power Act (16 U.S.C. 825q–1(b)) in accordance with the amendment made by subsection (a).
15.

Appropriations
In addition to amounts otherwise available, there is appropriated to the Commission for fiscal year 2024, out of any funds in the Treasury not otherwise appropriated, $200,000,000, to remain available until expended, to carry out—
(1)
sections 4, 5, and 10; and
(2)
the amendment made by section 9.