HR6176-119

1. Short title This Act may be cited as the Electricity Transmission Scorecard Act.

2. Findings Congress finds the following: 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. Transparent, standardized performance data on transmission systems promotes cost-effective investment, prevents unduly discriminatory practices, and protects ratepayers. Existing reporting requirements are fragmented, inconsistent, and do not allow for meaningful comparison among transmission providers, RTOs, and ISOs. 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. 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. 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. The quality of economic, reliability, and environmental outcomes delivered to customers can improve as a result of performance-based accountability. 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.

3. Performance scorecard elements and verification 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: 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. 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. 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. 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. Capital expenditure bias, which shall assess the covered transmission owner’s balance of spending on capital investment versus operational and maintenance activities. 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. 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. 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. For purposes of this clause: 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— shares common ownership or controlling interest with the covered transmission owner or its parent entity; is a direct or indirect subsidiary of the covered transmission owner or its parent entity; 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 is otherwise determined by the Commission to have a financial, governance, or operational relationship that may reasonably be expected to influence interconnection prioritization. The term unaffiliated entity means any entity that— has logged an interconnection request with the covered transmission owner; and is not an affiliated entity. 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. 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. Any additional matters that— may be evaluated using outcome-based performance metrics identified by the Commission, giving preference to quantitative metrics over qualitative metrics; and 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. 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. 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. 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— regional grid operators, including Independent System Operators, Regional Transmission Organizations, transmission planning entities, and balancing authorities; interconnected electric utilities, including load serving entities and other transmission providers; owners of generation facilities, including utility-scale and merchant generators seeking interconnection or operating within the service territory of the covered transmission owner; and regulatory and oversight entities, including State public utility commissions, and applicable Federal or State energy, reliability, or environmental agencies. 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: 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— reflects weighted or capacity-adjusted averages of covered transmission owner-reported metrics, as appropriate; highlights significant intra-regional variation or performance outliers; and does not obscure material differences among transmission owners or regions. 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: 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. 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. 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. 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. 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. 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. 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. 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). 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). 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. 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. 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— requirements for the approval by the Commission of independent evaluators, including requirements that an independent evaluator— 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; 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 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; procedures for auditing the assumptions and methodologies used in applying performance metrics, including to detect selective reporting and ensure alignment with Commission-defined protocols; requirements to ensure that any single independent evaluator, or their parent company or subsidiary— 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 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; 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; 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 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. In carrying out this subsection, the Commission shall— 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; utilize the technical expertise of National Laboratories to assist in the training, evaluation, or approval of independent evaluators; 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 consult National Laboratories during periodic updates to the verification process, in coordination with any relevant stakeholder advisory group convened under section 5. 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. An audit under this subsection may be initiated— at the discretion of the Secretary; upon identification of material discrepancies in reported metrics; in response to concerns raised by a stakeholder advisory group convened under section 5; or as part of a randomized, rotating sample of reporting entities to support continuous oversight. The results of an audit conducted under this subsection shall be made publicly available not later than 2 months after completion of the audit. 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. 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. The Commission shall include in the rule issued under this section— 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; allowance for the use of proxies, estimates, or approximations only— where direct data are unavailable; and 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 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. In issuing any revisions to the rule under this section, the Commission shall ensure that— such revisions are based on the outcomes of any applicable technical conference held under section 5; the period for public comment on such revisions is not less than 90 days; and the final rule making such revisions is issued not later than 180 days after the close of such period for public comment. 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). The Secretary shall annually publish a report that compiles and analyzes scorecards submitted to the Secretary under subsection (a) and, for each metric— ranks the performance of reporting entities, grouped by market type and governance structure; and 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. 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— an assessment and comparison of the changes over time in utility performance regarding the metrics required to be included in the scorecards; evaluation of data quality, availability, methodologies, and verification practices relevant to the scorecards; and findings and recommendations regarding the scorecards provided by the technical conferences held and stakeholder advisory group convened under section 5.

4. Accessibility and public transparency 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. 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. 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.

5. Scorecard improvement The Commission shall hold public technical conferences not less often than once every 3 years to solicit stakeholder feedback on— the effectiveness of scorecard metrics in conveying the performance of a given reporting entity; the sufficiency and quality of the data disclosed in scorecards; the alignment of scorecards with Federal and State priorities, including affordability, reliability, and congestion reduction of transmitted electricity; and opportunities to refine metrics in light of emerging technologies, grid conditions, and energy markets. 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: 2 members representing State public utility commissions. 2 members representing covered transmission owners. 2 members representing independent power producers. 2 members representing Regional Transmission Organizations and Independent System Operators. 1 member representing the Electric Reliability Organization. 2 members representing transmission planning entities. 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. 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. 2 members with expertise in energy systems performance, representing academic or research institutions, including the National Laboratories. 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.

6. Definitions In this Act: The term Administrator means the Administrator of the Energy Information Administration of the Department of Energy. The term Commission means the Federal Energy Regulatory Commission. The term covered transmission owner means any entity, other than an Independent System Operator, Regional Transmission Organization, or transmission planning entity, that— owns, operates, or controls transmission facilities that are part of, or connected to the bulk-power system; provides, or is capable of providing, transmission service for the movement of electric energy, whether in interstate or intrastate commerce; and 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. 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). 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). 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— dynamic line rating systems; advanced power flow control devices; topology optimization tools and software-based reconfiguration technologies; real-time monitoring and sensing equipment that improves line utilization or visibility; and transformer upgrades, advanced transmission technologies, or reactive power equipment. 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. The term reporting entity means an entity required to submit a scorecard under this Act. 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. The term seam means a boundary or interface between neighboring transmission systems or grid operators. The term Secretary means the Secretary of Energy. 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. 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: 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). 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).