FERC Steps Toward Potential Overhaul of Transmission Planning and Cost Allocation

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The Federal Energy Regulatory Commission recently signaled potential wide-reaching reforms to regional electric transmission planning, cost allocation, and generator interconnection processes. Nearing the tenth anniversary of its landmark Order No. 1000, FERC issued an Advanced Notice of Proposed Rulemaking which examines whether existing approaches adequately account for the transmission needs of a changing resource mix. The ANOPR probes a wide range of topics and appears likely to generate specific proposals for fundamental reform to how we plan and pay for the grid.

This update highlights key proposals and expressed need for reform reflected in FERC’s lengthy ANOPR, published in the Federal Register July 27, 2021. Reform of this scale could touch every corner of the power sector and FERC is likely to receive a considerable volume of comments. We offer some specific considerations for stakeholders preparing comments on the ANOPR and note that comments will be due October 12, 2021. 

ANOPR Potential Reforms

FERC identifies the following potential areas for reform, inviting comments on the adequacy of current policies and previewing some specific proposals while inviting industry stakeholders to provide proposals of their own:

Regional Transmission Planning

FERC observes that regional transmission planning processes may not adequately model future scenarios to incorporate sufficiently long-term and comprehensive forecasts of future transmission needs, including the needs of anticipated future generations. FERC could restructure the regional planning process to consider a longer-term outlook and seeks comment on the inputs that should be considered, as well as the potential benefits and drawbacks of more a probabilistic planning approach. Transmission providers could also be required to identify geographic zones with significant renewable generation potential and plan transmission to facilitate its integration.

Cost Responsibility for Regional Transmission Facilities

The ANOPR echoes Order No. 1000 in seeking to identify the types of benefits relevant for cost allocation purposes, which beneficiaries are receiving those benefits, and how relative benefits accrue to various beneficiaries. For transmission facilities developed to meet the needs of a changing resource mix, FERC asks whether the existing approach to cost allocation fails to consider the full suite of benefits (and beneficiaries) such facilities produce. FERC could require transmission providers to establish a broader set of transmission benefits for purposes of cost allocation than currently in use, and potentially require a minimum set of benefits that must be considered. FERC could also propose a “portfolio approach” to regional cost allocation, where multiple transmission facilities are considered together, and their collective benefits measured.

Generator Interconnection Funding

In recent years, the generation fleet has shifted from predominantly centralized resources to include many smaller renewable generators that, due to their distance from load centers, often require extensive interconnection-related network upgrades. To FERC, this trend warrants revisiting the interconnection pricing policies established by its Order No. 2003. One potential reform is to no longer require interconnecting generators to pay the total cost of grid network upgrades and instead allocate the costs more broadly commensurate with an upgrade’s benefits. Eliminating participant funding could increase integration of generation by eliminating a potentially prohibitive cost assignment and increasing cost certainty to resources in the interconnection queue. At the same time, under a new approach to cost allocation more broadly, interconnection customers could be considered beneficiaries of transmission facilities that facilitate their interconnection even if those facilities were built prior to the generators entering the interconnection queue.

Generator Interconnection Queue Process

In addition to reforming interconnection cost responsibility, FERC proposes modifications to the interconnection queue process, including: mechanisms to discourage the practice of speculative interconnection requests; fast-tracking the process for generators committed financially to new regional transmission facilities; and fast-tracking requests that meet certain readiness criteria, such as a project with an executed PPA, or one sited at a previously developed point of interconnection. Most of the proposed reforms are geared toward addressing the chronic issue of significant queue delays and cost allocation uncertainty in most RTO/ISO interconnection processes.

Enhanced Transmission Oversight

Eyeing significant near-term investments in the transmission system, FERC is also weighing enhanced oversight of transmission planning and spending. Under one proposal, an independent entity would monitor costs and planning on a regional basis with the goal of identifying potentially excessive costs, including through inefficiencies between local and regional planning processes. That entity might operate independently of existing RTOs/ISOs and could refer problematic planning decisions to FERC. FERC also seeks input on involving state commissions in planning, citing Southwest Power Pool’s Regional State Committee as a vehicle for state input on matters of regional importance.

Specific Avenues for Public Input

Reform of this scale—particularly an overhaul to cost allocation—could touch every corner of the power sector. Acknowledging the myriad stakeholders and perspectives relevant to these issues, we note three areas in particular which might be worthy of consideration and comment.

First, the ANOPR may be a useful opportunity for proponents of a stronger framework for considering non-transmission alternatives in transmission expansion planning processes. In Order No. 890 and again in Order No. 1000, FERC directed transmission planners to give “comparable consideration” to non-transmission alternatives such as energy efficiency, energy storage, demand response, and distributed generation. Those orders did not, however, give concrete instructions for how to treat non-transmission alternatives or otherwise ensure comparable consideration. While the ANOPR does not call out the potential role of non-transmission alternatives, specifically, it does seek comment on the potential for “grid-enhancing technologies” to increase the capacity, efficiency, and reliability of transmission facilities and to reduce the cost of interconnection-related network upgrades. FERC considers storage technologies to be grid-enhancing technology, and the ANOPR leaves room in any case for open-ended comments on any related matters or alternative proposals commenters may wish to discuss. The ANOPR would seem to be an opportunity for FERC to consider again how non-transmission alternatives are considered in the regional transmission planning processes and how to better ensure they are considered on a truly comparable basis. Non-transmission alternatives may have a part to play in addressing FERC’s concerns with transmission cost oversight as well as regional transmission planning and associated modeling issues.

Second, while the ANOPR does not discuss its relevance to specific generation technologies, the proposed reforms are timely in light of recognized transmission planning challenges facing the growing offshore wind sector. Individual offshore wind projects would likely benefit from FERC’s proposed reforms to the generator interconnection process and greater coordination of that process with regional transmission expansion planning. At a sector scale, FERC would require transmission providers to identify geographic zones with the potential for large amounts of renewable generation, which would seem to dovetail with the Bureau of Ocean Energy Management’s identification and leasing of offshore wind energy areas. Requiring transmission providers to facilitate integration of projects in those areas could help overcome a major impediment to the sector’s growth and cost competitiveness.

Third, the ANOPR presents an opportunity for proponents of electric storage, electric vehicles (EV), and related charging infrastructure to weigh in on transmission planning and cost allocation reforms that would reduce barriers to implementation. Electric storage is projected to continue to grow exponentially in the U.S., with some analysts projecting 12 GWh or more added to the grid in 2021 alone. Likewise, some projections expect share of new car sales captured by EV to reach nearly 30% by 2030, and traditional automotive companies are starting to take notice (for example, General Motors committed this year to convert to all EV sales by 2035). Storage and EV build-out on a large scale will require significant investment in charging infrastructure, often in parts of the existing grid that do not currently have large loads. Thus, cost allocation proposals and regional transmission expansion planning innovations that could result from the ANOPR will be of significant interest to proponents of storage and EV infrastructure.

Comment Deadlines and Next Steps

Comments on the ANOPR are due October 12, 2021. Stakeholders may also submit replies to comments, which are due November 9, 2021. Following the comment period, FERC will consider whether to open a formal rulemaking on these issues.

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DISCLAIMER: Because of the generality of this update, the information provided herein may not be applicable in all situations and should not be acted upon without specific legal advice based on particular situations.

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