At a time of significant industry transformation driven by technological change and spurred on by environmental policy concerns, the Federal Energy Regulatory Commission (“FERC” or “Commission”) has now added a significant layer to the stack of policy debates – the future of transmission investment. Many states have seized the initiative in terms of establishing preferable resource mixes for in-state customers, and are spearheading significant pushes for greater renewable and storage resource deployment. FERC has now joined the fray by opening up the policy debate anew regarding how to spur (or whether to spur) additional transmission sector investment. The FERC order described below focuses on regulatory and market rules impacting transmission investment (Docket No. PL19-3-000). The agency also opened a companion docket requesting comments on the details of its policies regarding establishment of a public utility transmission owner’s stated return on equity (“ROE”) (Docket No. PL19-4-000). The Washington Energy Report will provide detailed summaries of these orders via our blog. FERC’s mention here of “an increased emphasis on the reliability of transmission infrastructure” (emphasis added) could signal an attempt to re-focus the U.S. Department of Energy’s resiliency concerns to an arena that gives FERC home-field advantage. Lest the states forget, FERC controls the price of admission for a ticket to the interstate transmission network, and this open-ended fact-finding effort bears a high likelihood of impacting the price of such tickets (for a large portion of the continental United States).

1. Overview

  • FERC Notice of Inquiry (“NOI”) – On March 21, 2019, FERC issued an NOI in Docket No. PL19-3-000 seeking a broad range of input from industry stakeholders on its currently-applicable policies for granting monetary/rate incentives to certain transmission facility developers and owners. Inquiry Regarding the Commission’s Electric Transmission Incentives Policy, 166 FERC ¶ 61,208 (2019) (“Incentives NOI”).
  • Industry Evolution Spurs Fresh Look at 13-Year Old Congressional DirectiveThe Incentives NOI directs commenters to address specific issues regarding, inter alia, the appropriate and applicable standards FERC should use to assess whether its current incentive ratemaking policies for transmission projects and services are consistent with Section 219 of the Federal Power Act (“FPA”). See 16 U.S.C. 824s (2012). Remarking that its FPA Section 219 policies were now nearly 13 years old, FERC recognized “there have been a number of significant developments in how transmission is planned, developed, operated, and maintained” and that it now had experience with “the records compiled in various incentives proceedings before the Commission . . . .” FERC went on to note the “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.”
  • Revisiting Congress’ FPA Section 219 Objectives The Energy Policy Act of 2005 added FPA Section 219, which directs the Commission to establish, by rule, “incentive-based rate treatments to promote capital investment in certain transmission infrastructure.” See, e.g., Pac. Gas & Electric Co., 160 FERC ¶ 61,018 (2017). In relevant part, FPA Section 219 specifies that FERC “shall establish, by rule, incentive-based (including performance-based) rate treatments” for transmission. Among other things, such FPA Section 219 incentives must: (1) benefit consumers by ensuring reliability and reducing delivered power costs through transmission decongestion; (2) promote capital investment in the enlargement, improvement, maintenance, and operation of all transmission facilities (regardless of ownership); (3) provide an ROE that “attracts new investment in transmission facilities (including related transmission technologies)”; and (4) encourage deployment of transmission technologies and other measures to increase the capacity and efficiency of existing transmission facilities and improve operations.
  • FERC’s Existing Incentives Implementation Program (Now Under Agency Review)To implement Congress’ FPA Section 219 directive, in 2006 FERC issued: (1) Order No. 679, which details how an applicant can obtain FERC rate incentives; see Order No. 679, FERC Stats. & Regs. ¶ 31,222; and in 2012 (2) the Transmission Incentives Policy Statement (which clarifies certain aspects of Order No. 679). See Promoting Transmission Investment Through Pricing Reform, 141 FERC ¶ 61,129 (2012). In Order No. 679 and the Transmission Incentives Policy Statement, FERC found that transmission facilities for which incentive rates are sought must “either ensure reliability or reduce the cost of delivered power by reducing transmission congestion.”
  • The Nexus Test Transmission project sponsors have been required to convince FERC there is a nexus between the incentive requested and reliability benefits/cost-reductions to customers. Among other things, Order No. 679 applicants have been required to show that the facilities in question: (1) resulted from a fair and open regional planning process that considers and evaluates the project for reliability and/or congestion and is found to be acceptable to the Commission; or (2) a project that has received construction approval from an appropriate state commission or state siting authority.

2. Incentives NOI — Highlights

The Incentives NOI brings within its ambit a very broad range of issues currently facing industry participants. The order focuses stakeholder responses by suggesting 105 specific questions on a wide range of topics, highlighted below in relevant part.

  • Review of Incentive Rate Assessment Criteria – FERC asks how it should assess applicant requests for FPA Section 219 incentives, including in particular, whether applicants must continue to demonstrate a nexus between “risks and challenges” faced by grid project proponents and the rate incentive sought. See Incentives NOI at P 15. FERC suggests, for example, that it might adopt various iterations of a “project benefits test,” that would screen (and monitor) if claimed forward-looking benefits actually deliver FPA Section 219 policy objectives to customers (i.e., reliability and lower costs). Id. at P 16. A third approach would focus on specific project characteristics, and differentiate/ limit incentive levels as between various types of projects and risk profiles. Id. at P 18.
  • Re-Focusing FPA Section 219 Policy Objectives – FERC recognizes that its transmission incentive approach has required direct linkages to applicant showings of expected improvements in reliability and lowered delivered costs. The agency notes, however, that FPA Section 219, as envisioned by Congress, could entail more tailored and granular project rate incentives tied to expected quantifiable project benefits based on identified project characteristics. Pointedly, FERC says: “we seek comment on what expected benefits or project characteristics warrant incentives.”
  • Differentiation of Project Characteristics and Benefits – The agency suggests a laundry list of possible project characteristics and benefit streams that could receive incentive rates, and are fair game for commenter input. The agency’s detailed discussion of various project characteristics shows its interest in retooling implementation of FPA Section 219 so that it better fits the pace of industry change (including, e.g., greater reliance on DERs, demand response, renewables, etc.). FERC culls out the following, notable, project characteristics for which it seeks industry feedback:
    • General reliability benefits and bespoke reliability benefits (i.e., ramping) (at P 22);
    • Delivered energy cost reductions (economic efficiency benefits) (at P 24);
    • Geographic/ locational siting incentives (at P 25);
    • Flexible transmission system operations (e.g., real time line ratings, etc.) (at P 26);
    • Security (at P 27);
    • Resilience (at P 28);
    • Existing facility improvements (at P 29);
    • Interregional projects (at P 30);
    • Locational constraint mitigation projects (at P 31);
    • Non-utility ownership (at P 32);
    • Order No. 1000 projects (at P 33); and
    • Non-regional transmission organization (“RTO”) region projects (at P 34).

3. Insight & Analysis

We provide the following first impressions on the possible paths forward for FERC in the wake of this broad inquiry, as well as an impact assessment relative to industry trends and various parties’ likely constituent interests in the proceeding.

  • Future of the Big Grid and Capital Allocation Regional market players and state regulators are deep in the throes of debate regarding distributed energy resources, renewable targets, storage usage/ownership, demand response, and whether the utility model itself remains viable or desirable in a declining load context. Those discussions have led parties to question the role of, and need for, large, high voltage transmission projects, and to investigate “non-wires alternatives.”[1] As well, investments in distribution infrastructure and smart grid technologies have grabbed attention and headlines, as utilities focus on their core local delivery networks.[2] In contrast, a recent Brattle Group report estimates $30 billion – $90 billion of incremental transmission investments will be necessary by 2030, and an additional $200 – $600 billion will be needed in the 2030- 2050 time frame.[3] Thus, as competition heightens for industry capital expenditures and other opportunities, FERC’s policies on Big Grid financial incentives/disincentives will be critically important to how investors view various asset investment opportunities – not to mention whether/when/how generation and demand resources in different regions will come to market and/or be priced when they get there.
  • Technology – and “Flexibility” — Come to the NetworkThe agency’s order echoes similar themes to those currently being debated in the context of state-based market reforms (e.g., New York REV, Ohio’s Power Forward). Key to such efforts is a recognition that regulators should facilitate the equivalent of open-source platforms to foster – and directly integrate – new technologies that drive efficiency and customer value.[4] FERC’s NOI recognizes that technological innovations (such as real time line ratings and other technologies) hold potential to increase network usage and increase capacity or de-congest the network. FERC asks how the value of such improvements to the existing network should be incentivized and tracked. The agency similarly demonstrates that it understands that high-levels of renewable penetration will create new challenges for grid operations as it asks, for example, whether transmission incentives can be used as a tool for incentivizing the integration of resources that provide specific grid flexibility and ramping benefits.
  • Role of Incumbents and Transmission-Only CompaniesAlthough Order No. 1000 held promise for non-incumbent transmission owners, such parties have complained that RTO planning processes are dominated by incumbent-planned reliability-driven facilities and/or high voltage generator interconnection facilities, leaving little room for competition and third-party capital. Some reports voice similar criticisms.[5] By the same token, third-party grid investments for baseline network functionality and the participation models for the latter are still inchoate, and potentially raise North American Electric Reliability Corp. responsibility and security liability issues. To this point, the Incentives NOI specifically asks whether third-party grid ownership should be encouraged or discouraged. Moreover, FERC wants to know if transmission-only companies should be granted incentive ROE adders, and on what basis. It will be interesting to watch whether and how FERC discusses the relative benefits of transmission-only asset ownership (i.e., regarding whether vertical disaggregation still holds pro-market value for commodity buyers and sellers in RTO markets). Vertical market power concerns are at the heart of important emerging market issues in related contexts (i.e., such as the role of the “Utility of the Future” in energy supply, and whether ownership and control of batteries by utility-wires-owners violates legal restrictions in place due to such vertical market power concerns).[6]
  • Non-RTO Area/ Non-Utility Investment Opportunities (RTO Planning Process Deemphasized ?) – FERC has requested that stakeholders comment on whether/ how incentives should be granted in non-RTO regions, and if the agency should consider policies that incent entry of non-utilities (read: Google, Amazon, etc.). In its previous orders and policies, FERC focused laser-like attention on whether rate incentive proponents could show that the project in question had been approved in an RTO planning process (i.e., entailing stakeholder approval). Notably, the Incentives NOI lacks the type of (arguably stringent) Commission verbiage used in previous orders about the importance of ensuring that all new transmission-build runs through the RTO planning process gauntlet. The agency may be signaling that it will allow for more flexibility and consider over-riding the RTO planning process deadlocks when the public interest requires it (e.g., to green-light large-project renewable integration efforts such as transmission for offshore wind, and for west-to-east transfer capability that would move wind to eastern markets). This effort could be viewed in line with the agency’s new approach to fast-tracking LNG terminal approvals.[7]
  • Granularity: Project-Specific Analysis and Product Differentiation The Incentives NOI suggests FERC’s willingness potentially to engage in far more granular and empirical analyses on a project-by-project basis than it does today. The agency asks whether project-specific benefit streams must be demonstrated and tracked, for example – which could require applicants to tender and defend more sophisticated operational and economic modeling outputs than the agency reviews today under FPA Section 219.
  • Performance Based Ratemaking & Monitoring – FPA Section 219 references the agency’s flexibility to rely on performance based ratemaking, instead of traditional cost-of-service rates. As we note above, states such as New York and Ohio are currently in the process of establishing rules for incumbent utilities under a Utility of the Future construct – which some believe inexorably entails a greater reliance on performance-based measures to set utility revenue levels.[8] FERC recognizes that the same type of performance-based incentives may be used as a tool under FPA Section 219, and asks the industry how it should develop appropriate standards and criteria for measuring whether a particular incentive applicant has met pre-established performance criteria identified as a pre-condition of granting such incentives. It will be interesting to note whether and how FERC develops meaningful, federally-applicable performance metrics for transmission owners – particularly in the context of facilities that are subject to the operational requirements of a third-party, not-for-profit, RTO or independent system operator.
  • Directional Process Note: the Vagaries of Regulatory Brainstorming FERC NOIs in general, and this one in particular, may be objectively viewed as having two purposes: regulatory research & development and legal insulation from subsequent attacks by interested parties in the courts.[9] Thus, in the past, FERC has issued NOIs as a springboard for launching more targeted administrative actions into specific subject-matter areas. Comments received in previous NOI processes have provided impetus and support for the agency to investigate market and structural fixes that would otherwise be more circumscribed in the context of party-specific adjudication proceedings (and would carry higher legal risk for the agency).[10] This NOI could very well signal additional, more-targeted FERC inquiries into topic-specific areas (perhaps through spin-off rulemaking or technical conference efforts).
  • Security and Resiliency – While reliability has been a long-time concern of the Commission’s, FERC appears to be framing the reliability issue with an emphasis on security and resiliency rather than the traditional operational-centric view of reliability (see PP 27-28). The Commission may tie this NOI into the Commission’s ongoing resiliency and cyber-security initiatives. The industry could use this proceeding as a way to introduce new technologies or concepts into these debates as well.