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Introduction

On May 13, 2024, the Federal Energy Regulatory Commission (FERC) issued a final rule to improve regional electric transmission planning and cost allocation. This explainer provides an overview of the final rule, titled Order No. 1920, that adopts various requirements concerning how transmission providers conduct long-term regional transmission planning and 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 role of states, and how to navigate these changes as a stakeholder.

This explainer is organized into four major sections:

• Executive Summary
• Key Decisions of the Final Rule
• FAQs
• Glossary

This explainer summarizes some of the reforms of the final rule and should not be relied upon as a legal document. Additional details and the final regulatory text that governs these reforms are available in the Order No. 1920 Final Rule.

Executive Summary

Transmission Reform: From Notice of Proposed Rulemaking to Final Rule

Order No. 1920 builds 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 directs transmission providers to adopt reforms to improve long-term assessments of transmission needs and adequately prepare for the future of the electric grid. In order to require transmission providers to adopt these reforms, Order No. 1920 modifies FERC regulations 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, FERC 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.[1] This level of engagement helped shape the largest record ever filed at FERC. While Order No. 1920 adopted many of the processes and reforms proposed in the NOPR, FERC revised certain parts of the proposed reforms and declined to adopt others based on the record developed through public comment.[2]

The NOPR identified and made proposals to address shortcomings in established regional transmission planning processes and focused on exploring ways to conduct and coordinate more effective and longer-term regional transmission planning. It also focused on the allocation of costs of transmission facilities that are identified through long-term regional transmission planning. Many commenters agreed with FERC that existing transmission planning and development has been inefficient and piecemeal, as well as without adequate consideration of long-term needs and more efficient regional facilities. Many commenters also agreed that the regional transmission planning processes in use were unjust and unreasonable without significant reform. 

The reforms established by Order No. 1920 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 also requires a process to develop one or more cost allocation methods that are specific to long-term transmission facilities identified through the planning processes outlined in the final rule. But, Order No. 1920 does not change existing regional cost allocation methods for other facilities. 

Key Decisions of the Final Rule

1. Long-Term Regional Transmission Planning

Order No. 1920 adopts the NOPR proposal to require transmission providers in each transmission planning region to conduct long-term regional transmission planning. This type of planning uses a sufficiently long-term, forward-looking, and comprehensive approach. Consistent with this requirement, Order No. 1920 established the following framework for such planning.

1. Conduct long-term scenario planning to identify long-term transmission needs, as well as long-term regional transmission facilities that address those needs
2. Use seven required benefits to evaluate long-term regional transmission facilities
3. Further evaluate long-term regional transmission facilities to determine whether they are either more efficient or cost-effective transmission solutions
4. 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 states 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 long-term scenarios to identify long-term transmission needs and long-term regional transmission facilities to meet those needs. In long-term regional transmission planning, transmission providers must develop at minimum three distinct long-term scenarios using best available data inputs and no less than a 20-year transmission planning horizon. Providers must also reassess the scenarios at least every five years.

Figure 1. Long-Term Regional Transmission Planning Timeline.

To develop long-term scenarios, transmission providers must incorporate, at a minimum, seven factors to forecast the long-term landscape.[3]

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 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 and corporate commitments, and federal, state, local, and federally recognized Tribal policy goals[4]

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

Transmission providers must measure and use at least seven specified benefits in each long-term scenario to evaluate the benefit of potential long-term regional transmission facilities. In their evaluation, they must determine whether those potential facilities would more efficiently or cost-effectively address a long-term transmission need over a 20-year or longer time horizon.[5]

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, which displace 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

Although transmission providers are required to develop an evaluation process, they are not required to select identified transmission facilities for construction and development, ensuring transmission providers have the flexibility to balance competing interests and exercise engineering judgment.

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, transmission providers must make a good faith effort to consult with and seek support from relevant state entities in their planning region’s footprint. 

Order No. 1920 recognizes relevant state entities as 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. Relevant state entities will play an important role in the development of a transmission provider’s evaluation processes and selection criteria. 

2. Long-Term Regional Transmission Cost Allocation

In Order No. 1920, transmission providers in each transmission planning region are required to file one or more ex ante cost allocation methods that apply to selected long-term regional transmission facilities. An 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 transmission planning region. Proposed cost allocation methods must distribute costs in a manner that is at least roughly equal with estimated benefits.

Filing the cost allocation method in advance is critical because it provides certainty about how costs will be distributed before the transmission facilities are built. This filing helps all relevant stakeholders understand the financial implications from the outset and improves the odds that needed transmission will actually be built. While Order No. 1920 provides 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.

Engagement Period

Order No. 1920 establishes a six-month period when transmission providers must provide a forum to negotiate a cost allocation method(s) and/or a State Agreement Process with relevant state entities. 

Following this engagement period transmission providers may file, if the states agree to it, a State Agreement Process that could ultimately lead to an alternative cost allocation method. This alternative method also needs to be agreed upon by the relevant state entity or entities. If a State Agreement Process fails, then the default regional cost allocation method would be used to distribute costs.

State Agreement Process

The 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. A State Agreement Process is permitted, but not required. It may start before the facility is selected, but the process must be completed no later than six months after the selection.

Under a State Agreement Process, Order No. 1920 allows flexibility for states and transmission providers to customize processes and requirements. For example, relevant state entities will determine what is meant by agreement (e.g., unanimous, plurality, majority, etc.), what specific benefits are valued in order to arrive at a fair 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.

Transmission providers are permitted, but not required, to submit a State Agreement Process in addition to a default regional cost allocation method if the relevant state entities agree to such a process.

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 a facility that otherwise would not meet the transmission providers’ selection criteria. Order No. 1920 requires compliance filings to include the following information.[6]

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 requires 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.

Transmission providers must explain how they will consider these technologies in their long-term and existing regional transmission planning to increase transparency for stakeholders. Order No. 1920 states 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 addresses 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

In Order No. 1920, transmission providers must enhance transparency and stakeholder participation in regional transmission planning processes.

• Enhanced Transparency: Transmission providers must establish transparent criteria, models, and assumptions used in local transmission planning.
• Information Disclosure: Transmission providers must identify, and publicly post, local transmission needs that they identify through the local transmission planning process and potential facilities evaluated to address those needs.

Stakeholder Engagement

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 transmission 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.

Figure 2. Decision-Making Process for Enhanced Transparency.

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.

In addition, stakeholders have the opportunity to comment on compliance filings after transmission providers ultimately submit them to FERC for approval.

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, Order No. 1920 requires transmission providers to assess if existing transmission facilities above a specified voltage threshold can be “right-sized.” 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. Order No. 1920 includes requirements for transparency regarding the selection of right-sized replacement transmission facilities, and mandates that once a transmission provider identifies a facility for right-sizing, this information must be made public.

5. Interregional Transmission Coordination

Order No. 1920 requires transmission providers in neighboring transmission planning regions to modify their existing interregional transmission coordination procedures to align with long-term regional transmission planning reforms. Order No. 1920 established 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 regional transmission 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.[7]

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 generally 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. Why should I consider this final rule to be important to me and how can I participate in the process? 

A. 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. When preceded by a Notice of Proposed Rulemaking (NOPR), a final rule will identify significant substantive issues raised by commenters in response to the NOPR and explain the agency's responses.[8]

Once the final rule is issued, members of the public and interested parties have an opportunity to request a rehearing of the final rule. A rehearing allows for further review and consideration of the rule. Commenters can seek rehearing within 30 days after issuance of the final rule, pursuant to FERC Rule 713, 18 CFR 385.713. If a person or organization that sought rehearing disagrees with the outcome of FERC’s action on its request for rehearing, the person or organization can also file an appeal in federal court. Depending on the outcome, a new rulemaking process, a reopening of comments, or other actions may be required.

To learn more about how to file a request for rehearing, visit FERC’s How to File a Request for Rehearing webpage.

As noted above, stakeholders also have opportunities to engage with transmission providers as they develop compliance filings and stakeholders also can comment on such compliance filings when they are filed with FERC. 

Q. To which entities does this final rule apply?

A. Order No. 1920 applies 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 footprint. 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 promote a 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 OPP@ferc.gov 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 act of distributing electric power using low voltage transmission lines that deliver power 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, with actual implementation to follow FERC's approval of the regulated entity's compliance filing.

Generation - The act of producing electrical energy from other forms of energy (e.g., mechanical, chemical, or nuclear); also, the amount of electric energy produced, usually expressed in kilowatthours (KWh) or megawatthours (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 all shippers 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.

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. The federal right of first refusal pertains to instances where the federal government reserves the privilege to approve or reject proposed energy projects or transactions within its jurisdiction before they proceed.

Right-sized - If a new facility increases transfer capability while replacing an existing one, it's 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.