April 25, 2022

US FERC Issues Proposed Rule to Improve Regional Transmission Planning and Related Cost Allocation – Too Little, Too Late?


On April 21, 2022, the United States Federal Energy Regulatory Commission (FERC or Commission) issued a notice of proposed rulemaking (NOPR) entitled “Building for the Future Through Electric Regional Transmission Planning and Cost Allocation and Generator Interconnection” to improve regional transmission planning and cost allocation of certain types of transmission.

The NOPR is issued in Docket RM21-17-000 that FERC opened last July with a related advance notice of proposed rulemaking (ANOPR). This docket has seen active participation by interested parties and has included one public meeting. Comments on the NOPR are due 75 days from date of publication in the Federal Register. Reply comments are due 30 days after the initial comment deadline.

General Overview of the NOPR

The NOPR builds upon prior FERC Orders 888 in 1996, 890 in 2007 and 1000 in 2011 and is intended to remedy observed deficiencies in the FERC’s existing regional transmission planning and cost allocation requirements and to ensure that Commission-jurisdictional rates remain just and reasonable and not unduly discriminatory or preferential (as is required under the Federal Power Act).

Unlike the initial ANOPR, the NOPR does not propose direct reforms related to cost allocation for interconnection-related network upgrades, interconnection queue processes, interregional transmission coordination and planning, and oversight of transmission planning and costs, on which issues FERC states that it is continuing to develop a record and will propose additional reforms, as warranted. Concurrently with the NOPR, FERC issued a notice of a technical conference on Transmission Planning and Cost Management.

Highlights of the NOPR

I. Proposed Changes to Regional Transmission Planning

Transmission providers would be required to:

  • Conduct regional transmission planning on a sufficiently long-term, forward-looking basis to meet transmission needs driven by changes in the resource mix and demand;
  • Identify transmission needs through multiple long-term scenarios that incorporate a minimum set of factors, such as federal, state and local laws and regulations that affect the future resource mix and demand, trends in technology and fuel costs, resource retirements, generator interconnection requests and withdrawals, and extreme weather events;
  • Consider a proposed list of broader set of benefits of regional transmission facilities to meet these long-term transmission needs for the purposes of selection and cost allocation;
  • Establish transparent and not unduly discriminatory or preferential criteria which seeks to maximize benefits to consumers over time without over-building transmission facilities to select transmission facilities in the regional plan for purposes of cost allocation that address these long-term transmission needs; and
  • Consider dynamic transmission ratings and more modern flow-control technology and practices in formulating their transmission plans.

II. Proposed Changes to Regional Transmission Cost Allocation

Each FERC-regulated transmission provider would be required to:

  • Seek the agreement of relevant state entities within the transmission-planning region regarding the cost allocation for transmission facilities selected as part of long-term regional transmission planning.
  • Establish a cost allocation method for transmission facilities selected as part of long-term regional transmission planning that is an ex ante cost allocation method, State Agreement Process by which one or more relevant state entities may voluntarily agree to a cost allocation method, or a combination thereof.
  • Establish a cost allocation method for transmission facilities selected as part of long-term regional transmission planning that complies with the existing six Order No. 1000 regional cost allocation principles.

III. Proposed Changes to Generator Interconnection

Each FERC-regulated transmission provider would be required to evaluate, for selection and cost-allocation consideration, generator interconnection upgrade projects in which:

  • The transmitter identifies network upgrades in interconnection studies to address those interconnection-related needs in at least two interconnection queue cycles during the preceding five years (beginning at the time of the withdrawal of the first underlying interconnection request)
  • The interconnection-related network upgrade that meet those interconnection-related needs has a voltage of at least 200 kilovolts (kV) and/or an estimated cost of at least $30 million;
  • Those interconnection-related network upgrades have not been developed and are not currently planned to be developed because the interconnection request(s) driving the need for the upgrade has been withdrawn; and
  • The public utility transmission provider has not identified an interconnection-related network upgrade to address the relevant interconnection need in a generator interconnection agreement.

Notably, the NOPR does not expressly require any modification to any Independent System Operator or Regional Transmission Organization pro forma interconnection procedure or tariff-based interconnection agreement, although such conforming changes could eventually be expected.

IV. Proposed Amendments to Order No. 1000: Right of First Refusal

The NOPR proposes to amend Order No. 1000 to permit the exercise of a federal rights of first refusal for transmission facilities selected in a regional transmission plan for purposes of cost allocation, conditioned on the incumbent transmission provider establishing joint ownership of those facilities.

Our Initial Reactions

Despite decades of FERC attention and action (including the availability of significant economic incentives meant to encourage such investment), transmission investment is generally viewed as significantly lagging that required or desirable for a reliable and resilient grid that can accommodate increasing variable generation by wind, solar and other renewable resources and that can withstand extreme weather events that are happening with increasing frequency and intensity. Decarbonization of the grid and electrification of transportation and industry create their own new demands on the bulk power system.

Over a decade ago, we noted1 five matters that we viewed as required for an effective FERC policy framework for appropriate transmission development and investment. As we also noted then, and as is still the case, the issues are complicated and require a careful balancing of competing interests suggesting that longer-term and more participatory planning (even though we view these as necessary) alone will not be sufficient to result in necessary transmission development and investment and instead may serve only to risk further and potentially significant extensions of an already time-consuming process.

Additionally, pressure for further FERC action is concrete and significant. Transmission development and planning are inherently long-term activities, especially where local opposition exists, and currently can take decades. Thousands of megawatts of renewables—both offshore and onshore—are “queued” for interconnection, some of the organized market entities that FERC regulates have experienced extraordinary delays in processing interconnection applications and several states (including New York and New Jersey) are proceeding with their own significant transmission development efforts. The NOPR does not address the significant interconnection backlog and, unless FERC deals with interconnection, the NOPR may remain another well-intentioned think piece that brings no increased capacity and efficiency to the grid that is needed to improve reliability and resiliency of the bulk power system.



1 In our article “Current Conflicts in U.S. Electric Transmission Planning, Cost Allocation and Renewable Energy Policies: More Heat than Light?” in the December 2010 issue of The Electricity Journal.

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