Explainer on the Transmission Planning and Cost Allocation Final Rule

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Introduction

On May 13, 2024, the Federal Energy Regulatory Commission (FERC or Commission) issued a final rule, Order No. 1920,[1] to improve regional electric transmission planning and cost allocation. After the issuance of the final rule, the Commission received requests for rehearing and clarification, which the Commission addressed in a rehearing order, Order No. 1920-A,[2] on November 21, 2024. Order No. 1920-A clarifies and modifies some requirements of Order No. 1920 including, but not limited to, state involvement in long-term regional transmission planning and cost allocation. One such provision is the requirement of state consultation before any amendment to a long-term regional transmission cost allocation method.[3] Additionally, on April 11, 2025, the Commission issued a second rehearing order, Order No. 1920-B.

This explainer provides an overview of the orders, which adopt requirements concerning long-term regional transmission planning processes and how transmission providers should allocate the costs of transmission facilities planned through those processes. This explainer will help you understand which policies have changed for regional transmission planning, including the improved transparency of planning processes and amplified role of states, and how to navigate these changes as a stakeholder.

This explainer is organized into three major sections:  

• Key Decisions of Order No. 1920 and Order No. 1920-A
• FAQs
• Glossary

This explainer summarizes some of the reforms of the final rule and the rehearing order but should not be relied upon as a legal document. Additional details and the final regulatory texts that govern these reforms are available in the Order No. 1920 Final Rule and the Order No. 1920-A Rehearing Order and the Order No. 1920-B Rehearing Order.

Spotlight on Administrative Process: Orders on Rehearing for Rulemakings

Once the Commission issues a final rule, interested stakeholders and members of the public have an opportunity to seek rehearing of the rulemaking. Participants in the rulemaking can request rehearing (a change in the rule) or clarification (further explanation) within 30 days after issuance of the final rule. The rehearing process allows for further review and consideration of the rule. If a person or organization that sought rehearing disagrees with the outcome of the Commission’s action on its request for rehearing, the person or organization can file an appeal in federal court.

The rehearing process serves several important purposes:

1. Review and Correction: It allows the Commission to review and potentially correct any errors in its final decision or order through a rehearing order. This ensures that the decision is fair and legally sound. In the context of rulemaking, as here, a rehearing order might change the regulations from what had been written in the original order. 
2. Clarification: The rehearing process and a rehearing order can provide clarification on specific points, which can help the parties involved understand the decision better and how it applies to them.
3. Legal Prerequisite: Filing for rehearing is often a necessary step before a party can seek judicial review in federal court. Without requesting a rehearing, parties typically cannot challenge the Commission decision in court.

Executive Summary

Transmission Reform: From Notice of Proposed Rulemaking to Final Rule

Order No. 1920 and Order No. 1920-A build upon electric transmission planning and cost allocation requirements developed over the last several decades in Order No. 888, Order No. 890, and Order No. 1000. In large part, Order No. 1920 and Order No. 1920-A direct transmission providers to adopt reforms to cost allocation processes and improve long-term assessments of transmission needs to adequately prepare for the future of the electric grid. The legal basis for the orders is the Commission’s authority under section 206 of the Federal Power Act to ensure that rates, terms, and conditions for transmission service remain just and reasonable.

In April 2022, the Commission issued a Notice of Proposed Rulemaking (NOPR) that proposed several changes to existing transmission planning processes and invited comments from the public. After the public comment period closed, FERC reviewed and analyzed more than 30,000 pages of comments and reply comments from nearly 200 stakeholders representing the electric power industry, environmental, consumer and other advocacy groups, and state and other government entities.[4] This level of engagement helped shape the largest record ever filed at the Commission. On May 13, 2024, Order No. 1920 adopted many of the processes and reforms proposed in the NOPR, but FERC revised certain parts of the proposed reforms and declined to adopt others based on the record developed through public comment.[5] Then, on November 21, 2024, the Commission issued Order No. 1920-A, modifying Order No. 1920 by, among other things, elevating the role of state regulators in the transmission planning and cost allocation processes.

The reforms established by Order No. 1920 and Order No. 1920-A are intended to ensure continued electric service in the face of growing reliability challenges and greater access to lower-cost generation supplied by a wide range of resources. These reforms are all pursuant to FERC’s mandate to ensure just and reasonable transmission rates and practices affecting those rates. Order No. 1920 and Order No. 1920-A require a process to develop one or more cost allocation methods that are specific to long-term transmission facilities identified through the planning processes as well as opportunities for states to develop their own cost allocation methods and/or state agreement processes as outlined in the final rule.

Key Decisions of Order No. 1920 and Order No. 1920-A

1. Long-Term Regional Transmission Planning

Order No. 1920, Order No. 1920-A, and Order No. 1920-B (the orders) require transmission providers in each transmission planning region (region) to conduct long-term regional transmission planning (long-term planning). This type of planning uses a sufficiently long-term, forward-looking, and comprehensive approach.[6] Transmission planners should identify long-term transmission needs and facilities to address those needs, then use the guidance in the orders for cost-benefit analyses.

The orders establish that transmission planners should use the following framework for long-term planning.

1. Conduct long-term scenario planning to identify long-term transmission needs, as well as potential long-term regional transmission facilities that may address those needs
2. Further evaluate potential long-term regional transmission facilities to determine whether they are efficient or cost-effective transmission solutions
3. Use transparent selection criteria to select long-term regional transmission facilities for potential inclusion in the regional transmission plan

Long-Term Scenarios

Order No. 1920 stated that transmission providers must properly account for known causes of long-term transmission needs to ensure just and reasonable rates. To do so, transmission providers must use scenarios to identify long-term transmission needs and transmission facilities to meet those needs. In long-term planning, transmission providers must develop a minimum of three distinct long-term scenarios using best available data inputs and no less than a 20-year transmission planning horizon, and must reassess the scenarios at least once every five years. Order No. 1920-A clarified that if relevant state entities request additional scenarios to inform their consideration of cost allocation methods and/or state agreement processes, transmission providers must develop a reasonable number of additional scenarios. The orders recognize relevant state entities as any state entity responsible for electric utility regulation, such as the state utility commission, or for siting electric transmission facilities within the state or portion of a state located in the region.  

To develop long-term scenarios, transmission providers must incorporate, at a minimum, seven categories of factors to forecast the long-term landscape.[7]

1. Federal, state, local, and federally recognized Tribal laws affecting resource mix and demand
2. Federal, state, local, and federally recognized Tribal laws on decarbonization and electrification
3. State-approved utility integrated resource plans and load-serving entities’ expected supply obligations
4. Trends in fuel costs and in the cost, performance, and availability of generation, electric storage resources, and building and transportation electrification technologies
5. Generator retirements
6. Generator interconnection requests and withdrawals
7. Utility commitments and federal, state, local, or federally recognized Tribal policy goals that affect long-term transmission needs[8]

Order No. 1920-A clarified that transmission providers must consult with relevant state entities regarding how to incorporate state policies into scenarios.[9]                                                                                                                                                                                                                             

Mitigating Uncertainty

After developing at least three long-term scenarios, transmission providers must develop a sensitivity for each of the long-term scenarios. The sensitivity can be thought of as a “stress test” for the long-term scenario. Transmission providers are required to perform sensitivity analyses of uncertain operational outcomes like generation or transmission outages over a wide area from extreme weather events. Optionally, transmission providers may consider additional sensitivities, such as a cyber-attack, significant forecast error, or fuel price volatility.

Benefits of Transmission Facilities

Order No. 1920-A determined that transmission providers may measure and use seven benefits, first outlined in Order No. 1920, in each long-term scenario to evaluate the benefit of potential long-term regional transmission facilities.[10] In their evaluation, transmission providers must determine whether those potential transmission facilities would efficiently or cost-effectively address a long-term transmission need over a 20-year or longer time horizon.[11] Also, Order No. 1920-A stated that transmission providers may define and consider additional benefits for cost allocation purposes, including those agreed to by relevant state entities, so long as costs can be allocated in a way that is roughly commensurate with estimated benefits.[12] Given the modifications established in Order No. 1920-A, relevant state entities will be able to play a larger role in the development of a transmission provider’s evaluation processes and selection criteria.

The following are benefits which must be considered in the cost-benefit analysis of long-term transmission planning: 

1. Avoided or deferred reliability transmission facilities and aging infrastructure replacement: Calculates the costs that are avoided when proposed new long-term regional transmission facilities address reliability needs and eliminate, or delay, the need to replace existing infrastructure.  
2. Either reduced loss of load probability or reduced planning reserve margin: Calculates the reduction in frequency of power outages or the reduction in capital costs of generation needed to be built to meet planning reserve margins.
3. Production cost savings: Calculates the savings in fuel and other operating costs of generation that are realized when new long-term regional transmission facilities allow for the increased dispatch of lower-cost generators, displacing generation suppliers with higher production costs. This benefit also includes the reduction in market prices as lower-cost generation suppliers increasingly set market-clearing prices.
4. Reduced transmission energy losses: Calculates the reduction in total energy necessary to meet demand stemming from reduced energy losses during the movement (i.e., transmission) of power from generation to loads.
5. Reduced congestion due to transmission outages: Calculates the reduction in production costs resulting from avoided congestion during transmission outages.
6. Mitigation of extreme weather events and unexpected system conditions: Calculates the reduction in production costs during extreme weather events and unexpected system conditions, such as unusual weather conditions, fuel shortages, and generation and transmission outages.
7. Capacity cost benefits from reduced peak energy losses: Calculates the benefit of using a transmission facility to reduce the investment in power plants needed to meet peak electric usage, for example, on very hot days. These savings would be passed on to customers through lower generation capacity costs.

Evaluation and Selection of Transmission Facilities

In proposing evaluation processes, including selection criteria, transmission providers must provide clear and transparent criteria for evaluating specific transmission facilities. That is, their evaluations must present sufficient detail so that stakeholders understand why a particular long-term transmission facility was or was not selected. Under Order No. 1920, transmission providers must adopt an evaluation process and selection criteria that aim to maximize benefits accounting for costs over time without overbuilding transmission facilities. Transmission providers may also use a portfolio approach that considers multiple, rather than individual, long-term regional transmission facilities. When developing the evaluation process, the orders require that transmission providers make good faith efforts to consult with and seek support from relevant state entities in their region’s footprint.

It is important to note that transmission providers retain the flexibility to balance competing interests and exercise engineering judgment when making final selections. Transmission providers do not have to mechanically adhere to a set of scores, recommendations, or criteria.

Seven Factors to Forecast Long-Term Scenarios. Adapted from Jennifer Danis, Christoph Graf, Matthew Lifson, Kelly McGee, and Elizabeth B. Stein, “Guide to State Participation in PJM Long-Term Scenario Development Under FERC Order No. 1920,” Institute for Policy Integrity, December 2024.

2. Long-Term Regional Transmission Cost Allocation

In the orders, transmission providers in each region are required to file one or more default, or ex ante, cost allocation methods that apply to selected long-term regional transmission facilities. A default, or ex ante, cost allocation method sets a predetermined default method for distributing the costs of a long-term regional transmission facility among benefitting customers within a region. Proposed cost allocation methods must distribute costs in a manner that is at least roughly commensurate with estimated benefits. For example, if a long-term regional transmission facility is intended to connect certain types of resources, a cost allocation method agreed to by relevant state entities may allocate incremental costs to states with applicable laws, policies, and regulations that encourage or require the development or use of such resources.

Filing and receiving approval for the cost allocation method in advance is critical because it provides certainty about how costs will be distributed before the transmission facilities are built. When all relevant stakeholders understand the financial implications from the outset, it improves the odds that needed transmission will be built. While the orders provide flexibility, transmission providers may not propose to allocate costs of long-term regional transmission facilities based on project types, such as reliability, economic, or public policy requirements.

Significantly, Order No. 1920-A clarified that a transmission provider must include, in its compliance filing with the Commission, any long-term regional transmission cost allocation method and/or state agreement process agreed to by relevant state entities - even if the transmission provider has an alternative proposal. As part of this modification, the rehearing order clarified that transmission providers must provide all supporting evidence and/or justification related to the relevant state entities’ proposals. The Commission then makes the ultimate determination.

Before filing revisions to cost allocation methods or state agreement processes, Order No. 1920-A required transmission providers to add a state consultation requirement to their Open Access Transmission Tariff (OATT). In addition, Order No. 1920-A required transmission providers to document on their public websites the results of consultations prior to submitting an amendment to their OATTs. If applicable, transmission providers must describe their reasoning for not using the results of consultations with relevant state entities in their compliance filings.

Cost Allocation Approach Example

In Order No. 1920-A, the Commission provided example language of a cost allocation approach, at the request of relevant state entities in a multi-state region, to be used as an option in compliance with the rulemaking. Under the Appendix – Major Changes Incorporated in Order No. 1920-A, the Commission outlined steps to a default, or ex ante, method for cost allocation by transmission providers.

Engagement Period and State Agreement Processes for Cost Allocation

Order No. 1920 established a six-month period when transmission providers must provide a forum to negotiate a cost allocation method(s) and/or a state agreement process for relevant state entities. Order No. 1920-A clarified that, if relevant state entities request additional time to complete cost allocation discussions, then the Commission will extend the engagement period for up to an additional six months to engage in discussions. Order No. 1920-A also clarified that the Commission will extend any relevant compliance deadlines to accommodate an extension to the engagement period.

Following the engagement period, transmission providers may file, if the states agree to it, a state agreement process. A state agreement process gives relevant state entities the opportunity to meet and propose an alternative cost allocation method for a specific long-term regional transmission facility. It may start before the facility at issue is selected in the regional plan, but the process must be completed no later than six months after the selection. If a state agreement process fails, then the default regional cost allocation method would be used to distribute costs.

For example, in a state agreement process, relevant state entities may determine the level of agreement required for a proposal to pass (e.g., unanimous, plurality, majority, etc.), what specific benefits are valued in order to arrive at an alternative cost allocation method, and the length of time for negotiating alternative cost allocation methods, so long as the negotiations last no longer than six months after facility selection.

Voluntary Funding Opportunities

Transmission providers are required to provide relevant state entities and interconnection customers with the opportunity to voluntarily fund the cost (or a portion of the cost) of a facility that otherwise would not meet the transmission providers’ selection criteria. This could enable such a funded project to achieve selection in the regional plan and potentially move forward into development and service. Order No. 1920 required compliance filings to include the following information.[13]

1. Timely notice of voluntary funding opportunities and a meaningful opportunity for relevant state entities and interconnection customers to respond
2. The period when relevant state entities and interconnection customers may exercise the option to provide voluntary funding
3. The method that transmission providers will use to determine the amount of voluntary funding required to ensure that the long-term regional transmission facility meets the transmission providers’ selection criteria
4. The mechanism through which transmission providers and relevant state entities or interconnection customers will memorialize any voluntary funding agreement

3. Enhancing Alternative Transmission Technologies

Order No. 1920 required transmission providers to consider the following alternative transmission technologies: dynamic line ratings, advanced power flow control devices, advanced conductors, and transmission switching. The aim is to identify efficient and cost-effective solutions to meet transmission needs and optimize the transmission system without the need to build additional transmission facilities.

The orders state that transmission providers must outline and explain how they will consider these technologies in their long-term and existing regional transmission planning to increase transparency for stakeholders. Order No. 1920 stated that evaluation methods must ensure that stakeholders have a clear understanding of decisions made throughout the process.

4. Local Transmission Planning Inputs in the Regional Transmission Planning Process

Transmission providers conduct local transmission planning to address local needs on their individual transmission systems, such as replacing and upgrading power lines. The local planning results provide information for the regional transmission planning process. Order No. 1920 addressed concerns regarding the lack of adequate transparency and provides opportunities for meaningful stakeholder input in local transmission planning processes.

Enhanced Transparency of Local Transmission Planning Inputs in the Regional Transmission Planning Process

Stakeholders will have opportunities to review and comment on local transmission planning information through publicly noticed meetings. Transmission providers must establish a process for stakeholder engagement that includes meaningful opportunities to participate and provide feedback on local transmission planning before local transmission planning inputs are incorporated into the regional planning process.

Under Order No. 1920, the regional transmission planning process must include at least three publicly noticed stakeholder meetings per regional transmission planning cycle: Assumptions Meeting, Needs Meeting, and Solutions Meeting. The meetings must focus on each transmission provider’s local planning process. These meetings must be held before each provider’s local plan can be incorporated into the region’s planning models.

• Assumptions Meeting: Stakeholders will have the opportunity to review criteria, assumptions, and models related to local transmission planning.
• Needs Meeting: Stakeholders will have the opportunity to discuss identified reliability criteria violations and other transmission needs.
• Solutions Meeting: Stakeholders will have the opportunity to review potential solutions to address the identified violations and needs.

Transmission providers must also maintain certain timelines and practices that inform and involve stakeholders.

• Pre-meeting Posting: Meeting materials must be publicly posted at least five days prior to each meeting.
• Feedback Consideration: Transmission providers must allow for a minimum 25-day period after the Solutions Meeting for stakeholders to provide feedback on proposed solutions.
• Responsive Engagement: Transmission providers must respond to stakeholder questions or comments during the meetings in a manner that allows for meaningful participation.
• Dispute Resolution: Disputes regarding transparency or planning inputs should follow existing resolution processes under Order No. 890.

Additionally, under Order No. 1920, transmission providers in each region must provide notice, such as on their public website, of the deadline for relevant state entities to communicate their agreement on a long-term regional transmission cost allocation method and/or a state agreement process. Further committing to transparency, Order No. 1920-A determined that the costs and benefits associated with project selection are required to be put on a transmission provider’s OASIS page[14] or other password-protected website for stakeholder access. Specifically, Order No. 1920-A clarified that transmission providers must make publicly available a breakdown of how estimated costs of a selected long-term regional transmission facility will be allocated by transmission pricing zone and a quantification of the estimated benefits per zone.

Right-Size Replacement Transmission Facilities

Right-sizing refers to replacing an existing transmission facility with a new replacement transmission facility that increases transmission capacity to meet expected needs. Instead of simply replacing aging facilities, the orders require transmission providers to assess if existing transmission facilities above a specified voltage threshold can be “right-sized.”[15] Right-sized replacements may better address long-term transmission needs, replacing aging, existing transmission facilities with new facilities while simultaneously increasing overall transmission system capacity. Transmission providers must submit estimates of these facilities for planning, proposing a threshold not exceeding 200 kilovolts.  

Transmission providers must evaluate right-sized replacements alongside other solutions and propose a point in time for submitting estimates of anticipated in-kind replacements of their existing transmission facilities early in each planning cycle. If identified, right-sized replacements are evaluated for efficiency and cost-effectiveness.

In terms of cost allocation, transmission providers may propose their own cost allocation method for selected right-sized replacement transmission facilities. The orders include requirements for transparency regarding selected right-sized replacement transmission facilities, and mandates that once a transmission provider selects a facility for right-sizing, the underlying replacement facility must be made public.

5. Interregional Transmission Coordination

Encouraging transmission lines that connect two or more regions can also meet the goals of the Commission for a more efficient and cost-effective grid. Thus, Order Nos. 1920 and 1920-A require transmission providers in neighboring regions to modify their existing interregional transmission coordination procedures to align with the long-term planning reforms. The orders establish the following requirements to adapt existing procedures with this requirement.

1. Require transmission providers to share information regarding long-term transmission needs and identify and jointly evaluate interregional transmission facilities to address those needs
2. Allow entities to propose interregional transmission facilities as more efficient or cost-effective solutions to long-term transmission needs

Transmission providers are mandated to make the following information publicly available through their website or e-mail list to enhance transparency and information sharing.

1. Long-term transmission needs discussed in interregional transmission coordination meetings
2. Interregional transmission facilities proposed or identified as part of long-term planning
3. Details such as voltage level, estimated cost, and estimated in-service date of proposed interregional transmission facilities
4. Results of cost-benefit evaluations for such interregional transmission facilities, including overall benefits and region-specific benefits
5. Selection of interregional transmission facilities to meet long-term transmission needs, if any

These reforms aim to ensure that identified long-term transmission needs are considered in interregional coordination and cost allocation processes thereby promoting fair rates.

FAQs

Q. What is FERC’s role in regulating electricity transmission and distribution?

A. In most parts of the United States, FERC is responsible for ensuring that the rates, terms, and conditions that apply to the transmission of electricity in interstate commerce are just, reasonable, and not unduly discriminatory or preferential. This responsibility is outlined in the Federal Power Act.

In some areas of the country, however, such as Alaska, Hawaii, and much of Texas (which has a separate transmission grid), transmission of electricity is not considered to be “interstate commerce” and thus for the most part does not come under FERC electric jurisdiction. In addition, FERC’s jurisdiction does not extend to the rates, terms, and conditions for the distribution of electricity, which is instead typically regulated by a state or local agency (such as a state public utility commission) with jurisdiction over retail electric rates (i.e., the rates individual consumers pay each month in their electricity bills).

When FERC determines that transmission rates and practices affecting those rates are unjust and unreasonable, it can seek to implement replacement rules that will be just and reasonable, pursuant to the Federal Power Act. This is what FERC did in this rulemaking, mandating changes to long-term regional transmission planning and cost allocation by transmission providers.

Q. How can I participate in the transmission planning process? 

A. As noted above, stakeholders have opportunities to engage with transmission providers as they hold local transmission planning meetings. Also, stakeholders can comment on transmission providers’ compliance filings when they are filed with FERC. Other stakeholder meetings may occur as part of the development of regional transmission plans, but that will depend on the region.  For more resources, consider contacting your state public utilities commission, which can be found through naruc.org, or state consumer advocate’s office, which can often be found at nasuca.org. 

Q. To which entities does this final rule apply?

A. Order Nos. 1920 and 1920-A apply to all transmission providers (i.e., public utilities that own, control, or operate transmission facilities) that have an Open Access Transmission Tariff (OATT) on file with FERC. A Regional Transmission Organization (RTO)/Independent System Operator (ISO) transmission planning region will submit a compliance filing, including proposed revisions to their OATTs, on the behalf of transmission providers within their footprints. Transmission providers in non-RTO/ISO transmission planning regions will submit individual compliance filings, including proposed revisions to their respective OATTs. FERC’s map of transmission planning regions is available here: Regions Map Printable Version Order No. 1000.

Q. I represent a Tribal government or utility and am interested in transmission planning. Are there more resources that describe Tribal participation at FERC?

A. As noted in its Policy Statement on Consultation with Indian Tribes in Commission Proceedings, FERC recognizes the unique relationship between the United States and Tribes as defined by treaties, statutes, and judicial decisions and has committed to adhere to the government-to-government relationship between itself and federally recognized Tribes. For more information on FERC’s tribal relations, as well as FERC’s Policy Statement on Consultation with Indian Tribes in Commission Proceedings, visit FERC’s Tribal Relations webpage.

To Learn More

Please contact FERC’s Office of Public Participation (OPP) by e-mail at [email protected] or by phone at (202) 502-6595. OPP’s website also provides additional information and resources about this process.

To find additional information, check out OPP’s Transmission NOPR Explainer.

Glossary

Demand - Electrical consumption of a customer or area at a particular moment in time. Often averaged over an hour, and thus usually expressed in kilowatts or megawatts rather than kilowatt-hours or megawatt-hours and used interchangeably with “load” when referring to energy requirements for a given customer or area.

Distribution - The process of transporting electric power using low voltage transmission lines for delivery to retail customers.

Dynamic line ratings - This flexible rating system for how much electricity a transmission line can carry is updated at least every hour or more frequently and takes into account things like the temperature of the air, wind speed, how much sun is shining on the line, and even the sag or tension in the power line as a real-time way of managing power lines based on what is happening around the power line.

Electric transmission - The process of transporting large quantities of electricity from the point of generation to the distribution networks that deliver the electricity to consumers.

Energy management system ­- A system of computer-aided tools used by operators of electric utility grids to monitor, control, and optimize the performance of the generation or transmission system.

Final rule - A final rule sets out new or revised requirements, or removes existing requirements, for regulated entities that must comply with the requirements. A final rule also states when the requirements will become effective. Actual implementation follows after FERC's approval of the regulated entity's compliance filing.

Generation - The process of producing electrical energy from various fuel sources (e.g., fossil fuel, nuclear, solar, wind etc.); also, the amount of electric energy produced is usually expressed in kilowatt-hours (KWh) or megawatt-hours (MWh).

Gigawatt (GW) - A unit of electrical power, equal to one billion watts.

Kilovolt (kV) - A unit of electromotive force, equal to 1,000 volts.

Load - The total amount of power carried by an electric system at a point in time, often used synonymously with the term demand.

Long-term scenarios - Scenarios that use various assumptions with best available data inputs about the future electric power system over a sufficiently long-term, forward-looking transmission planning horizon to identify long-term transmission needs and enable the identification and evaluation of transmission facilities to meet such transmission needs.

Megawatt (MW) - 1 million watts of electricity.

Megawatt hour (MWh) - 1,000 kilowatt-hours or 1 million watt-hours.

Notice of Proposed Rulemaking (NOPR) - A document issued by a federal agency that describes proposed new rules and regulations or proposed changes to existing rules and regulations. FERC issues a NOPR as part of the rulemaking process and, typically, before issuance of a final rule.

Open Access Transmission Tariff (OATT) - An electronic transmission tariff accepted by FERC requiring the transmission provider to furnish all customers with non-discriminating service comparable to that provided by transmission owners to themselves.

Public Utility - Any person who owns or operates facilities subject to the jurisdiction of FERC.

Relevant State Entities - Any state entity responsible for electric utility regulation or siting electric transmission facilities within the state or portion of a state located in the transmission planning region, including any state entity as designated for that purpose by state law.   A state public utility commission is a standard example, but not the only type. 

Right of First Refusal - A legal provision granting a specific entity the opportunity to purchase or develop energy resources or infrastructure before it is offered to other parties.

Right-sized - If a new facility increases transfer capability while replacing an existing facility, it is considered right-sized.

Rule - Federal regulations are known as rules and published in the Federal Register as well as updated annually in the Code of Federal Regulations. Rules are established by government agencies, as opposed to laws which are passed by the legislature. The rules help explain laws or policies and describe how a government agency works.

Rulemaking - In the context of the federal government, the term refers to the systematic process through which federal agencies formulate, amend, or repeal rules and regulations that are subsequently published in the Code of Federal Regulations.

Transmission Provider - A public utility (or its designated agent) that owns, controls, or operates facilities used for the transmission of electric energy in interstate commerce and provides transmission service under the tariff.