FERC Issues Notice of Inquiry Regarding Electric Transmission Incentives Policy


According to FERC Chairman Chatterjee, the electric transmission incentives NOI and a concurrently-released NOI on the Commission’s ROE policy “will be critical to ensuring that the energy revolution we’re currently undergoing results in more reliable services and lower prices for customers.” The electric transmission incentives NOI “asks very important questions about whether the Commission should be focused on incentivizing projects with risks and challenges or thinking more broadly about the reliability and economic benefits that transmission projects can provide.” Comments are due 90 days, and reply comments are due 120 days, after publication in the Federal Register.

On March 21, 2019, the Federal Energy Regulatory Commission (“FERC” or “the Commission”) issued a Notice of Inquiry Regarding the Commission’s Electric Transmission Incentives Policy (the “NOI”) in Docket No. PL19-3-000.1 The NOI seeks comments on the scope and implementation of the Commission’s transmission incentives policy, citing numerous developments in transmission planning and development in the 13 years since FERC first promulgated its electric transmission incentives regulations and the seven years since FERC issued its last policy statement on the topic.

Section 219 of the Federal Power Act (“FPA”) requires the Commission to establish rules providing incentive-based rate treatment for electric transmission in interstate commerce by public utilities, for the purpose of benefitting consumers by ensuring reliability and reducing the cost of delivered power by reducing transmission congestion.2

In 2006, the Commission issued Order No. 679, which promulgated its electric transmission incentives policy and established various incentives for transmission projects.3 To qualify for incentive rate treatment, Order No. 679 clarified that an applicant must, as a threshold matter, demonstrate that the transmission facilities will either enhance reliability or reduce the cost of delivered power by reducing transmission congestion. Noting that “[n]ot every incentive will be available for every investment,” the Commission further required that an applicant show there is a nexus between the incentives being requested and the investment being made.4 In applying the nexus test, the Commission explained it would consider “whether the total package of incentives is tailored to address the demonstrable risks and challenges faced by the applicant in undertaking the project.”5 According to the Commission at the time, “the most compelling case for incentives are new projects that present special risks or challenges, not routine investments made in the ordinary course of expanding the system to provide safe and reliable transmission service.”6 FERC further clarified its policy on the nexus test and incentive ROEs based on project risks and challenges in a 2012 Policy Statement.7

The NOI is aimed at determining whether the Commission’s electric transmission incentive policies continue to satisfy the requirements of FPA section 219, particularly in light of various developments that have changed the way transmission facilities are planned, developed, or operated. ”Th[e]se changes include the Commission’s issuance of Order No. 1000,8 an evolution in the generation mix and the number of new resources seeking transmission service, shifts in load patterns, and an increased emphasis on the reliability of transmission infrastructure.”9 To aid in its re-evaluation of the electric transmission incentives policy, the Commission requests public comments on the following issues.

Approaches to Incentive Policy

The Commission seeks feedback on the continued effectiveness of its traditional “risks and challenges” approach to granting transmission incentives. The NOI asks whether (and, if so, how) the Commission should employ alternative approaches, such as granting incentives based on expected project benefits (i.e., ability to achieve reliability or cost reduction benefits) or project characteristics (e.g., projects located in regions with persistent needs, interregional transmission projects, projects unlocking constrained resources, or projects including specific transmission technologies). The NOI requests commenters to consider how each approach should be implemented, as well their respective benefits and drawbacks.

Incentive Objectives

The NOI seeks comment on the specific types of expected benefits or project characteristics that the Commission should incentivize. To that end, the NOI asks commenters to consider how to define each type expected benefit or project characteristic, whether and how to quantify or measure such benefits or project characteristics, how to incentivize such benefits or project characteristics, and the legal basis, extent, and nature of the incentives.

Benefits or project characteristics for consideration include, but are not limited to:

  • Reliability Benefits: tailoring incentives to promote projects significantly enhancing reliability above what is required by NERC reliability standards or other planning criteria.
  • Economic Efficiency Benefits: projects that reduce congestion, and thereby promote efficient dispatch of resources and additional generation.
  • Persistent Geographic Needs: projects addressing regions experiencing chronic, long-term congestion and requiring operating procedures that ensure long-term reliability.
  • Flexible Transmission System Operation: projects enhancing flexibility of the transmission system to respond to generation mix changes and evolving load patterns, for example through increased line rating precision, greater power flow control, and energy storage and other technologies.
  • Security: enhancements of and investments in physical and cybersecurity of jurisdictional transmission facilities.
  • Resilience: enhancements to the resilience of the transmission system (which the Commission has recently proposed to define as “the ability to withstand and reduce the magnitude and/or duration of disruptive events, which includes the capability to anticipate, absorb, adapt to, and/or rapidly recover from such an event”).10
  • Improving Existing Transmission Facilities: investment in technologies and other methods of enhancing the capacity, efficiency, and operation of existing facilities, such as advanced management software or application technologies, such as energy storage, to improve utilization of existing facilities.
  • Interregional Transmission Projects: projects that increase interregional coordination, help to eliminate seams issues, and promote more efficient power flow among regions.
  • Locationally Constrained Resources: projects that unlock location constrained generation resources with limited or no access to wholesale energy markets.
  • Ownership by Non-Public Utilities: incentives promoting joint ownership arrangements with non-public utilities.
  • Order No. 1000 Transmission Projects: blanket pre-approval through the use of a rebuttable presumption of three types of incentives (CWIP, abandoned plant, and regulatory asset treatment) for projects selected in a regional transmission plan for purposes of cost allocation.
  • Transmission Projects in Non-RTO/ISO Regions: extending incentives to projects in non-RTO/ISO regions.

Existing Incentives

The NOI additionally requests feedback on existing incentives, including comments on whether they remain relevant and appropriate, and whether the goals underlying an incentive could be incentivized more efficiently. In particular, the NOI seeks comments on whether the RTO participation incentive should be revised, as well as comments on the three other categories of ROE adders. The NOI also seeks input regarding non-ROE incentives, such as CWIP, regulatory asset/deferred recovery of pre-commercial costs, hypothetical capital structure, abandoned plant, and accelerated depreciation incentives.

Other Considerations

The NOI also includes questions regarding the appropriate duration for incentives granted, approaches for reviewing incentive applications, determination of the appropriate level of ROE incentives, and metrics for evaluating the effectiveness of incentives.

Comments on the NOI are due no later than 90 days, and reply comments are due no later than 120 days, after publication in the Federal Register.

1 166 FERC ¶ 61,208 (2019) (“NOI”).

2 16 U.S.C. § 824s (2012).

3 See Promoting Transmission Investment through Pricing Reform, Final Rule, 116 FERC ¶ 61,057¸ reh’g denied in part and granted in part, 117 FERC ¶ 61,345 (2006) (“Order No. 679”). Order No. 679 made various incentives available, such as: (1) adders to base Return on Equity (“ROE”): for risks and challenges of a transmission project; for forming a transmission-only company (“Transco”); for joining a regional transmission organization (“RTO”) or independent system operator (“ISO”); or for use of advanced transmission technology; (2) recovery of 100 percent of prudently incurred costs of facilities that are cancelled or abandoned due to factors beyond the control of the public utility (“abandoned plant incentive”); (3) 100 percent inclusion of construction work in progress (“CWIP”) in rate base; (4) hypothetical capital structures; (5) accelerated depreciation for rate recovery; and (6) recovery of prudently- incurred pre-commercial operations costs as an expense or through a regulatory asset. The Commission subsequently eliminated a standalone ROE adder for advanced technologies, opting instead to consider the deployment of advanced technologies in its overall nexus analysis when an incentive ROE is sought. See Promoting Transmission Investment Though Pricing Reform, Policy Statement, 141 FERC ¶ 61,129 at P 23 (2012) (“2012 Policy Statement”).

4 Order No. 679 at P 26.

5 Promoting Transmission Investment Through Pricing Reform, Order on Rehearing, 117 FERC ¶ 61, 61,345 at P 6 (2006) (“Order No. 679-A”).

6 Id. at 23.

7 See Promoting Transmission Investment Though Pricing Reform, Policy Statement, 141 FERC ¶ 61,129 at P 23 (2012) (“2012 Policy Statement”).

8 The Commission adopted Order No. 1000 in 2011 to make certain transmission planning and cost allocation reforms for public utility transmission providers. Order No. 1000: (1) requires that each public utility transmission provider participate in a regional transmission planning process that produces a regional transmission plan; (2) requires that each public utility transmission provider amend its Open Access Transmission Tariff to describe procedures that provide for the consideration of transmission needs driven by public policy requirements in the local and regional transmission planning processes; (3) removes from Commission-approved tariffs and agreements a federal right of first refusal for certain new transmission facilities; and (4) improves coordination between neighboring transmission planning regions for new interregional transmission facilities. See Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, Final Rule, 136 FERC ¶ 61,051 (2011).

9 NOI at P 13.

10 See 162 FERC ¶ 61,012 at P 23 (2018).

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