FERC Seeks Comments on Major Reforms to Regional Transmission Planning and Generator Interconnection Processes to Bolster Renewables

Issues with the Existing Regional Transmission Planning and Cost Allocation and Generation Interconnection Processes

The ANOPR lays out three main issues with the existing processes for transmission planning and cost allocation and generation interconnection.  First, the two processes largely operate separately. As a result, FERC believes the current regional transmission planning process may fail to adequately consider the transmission needs of future generation. This failure can lead to inefficient investment in transmission infrastructure and can push the costs of transmission network upgrades required to integrate new resources onto generators on a project-by-project basis. Such a process is not optimized to coordinate the interconnection of many projects that are envisioned as part of the resource mix evolution. Second, while FERC has sought to open transmission to nonincumbent and competitive providers, the current structure may over-incentivize local incumbent transmission planning rather than the regional transmission planning that FERC believes is better suited to accommodate the expansion of new and diffuse renewable resources.

Third, FERC is concerned that transmission rates resulting from the current process may not be just and reasonable because neither the transmission planning nor generator interconnection processes allocate project costs to the beneficiaries in proportion to estimated benefits. The ANOPR stipulates that the segmentation of regional transmission planning into reliability, economic, and public policy goals may fail to match the costs, benefits, and beneficiaries associated with multifaceted projects. For the generation interconnection process, FERC believes the current participant funding model utilized in RTOs/ISOs—where an interconnection customer is responsible for the costs of transmission network upgrades required to interconnect a project in exchange for defined capacity rights—creates both a free-rider problem and a lack of investment in projects with the potential for a significant system benefit (i.e., projects that allow for more interconnection customers to develop projects later or that reduce transmission congestion faced by existing projects) because the upfront costs are borne by a single generator and not the multiple parties (including load serving entities) who may benefit. The participant funding model also incentivizes interconnection customers to place multiple interconnection requests seeking positions in the queue that minimize their upgrade costs. This decreases the queue’s efficiency and often results in projects dropping out of the queue, causing significant interconnection uncertainty, variability, and delays. FERC is requesting comments on these three issues and any other issues related to transmission planning or generation interconnection that interested parties believe may result in unjust and unreasonable transmission rates.

Requests for Comment on Proposed Reforms

The ANOPR seeks comments on three broad categories of proposed reforms to transmission planning and cost allocation and generator interconnection. First, FERC proposes several reforms to the regional transmission planning and cost allocation process. These proposals center around including anticipated generation in future scenarios modeling during the planning process and identifying geographic zones with the potential to develop high amounts of renewable resources—MISO’s Multi-Value Projects and the Public Utility Commission of Texas’s Competitive Renewable Energy Zones exemplify this practice. FERC also requests comments on incentivizing regional, as opposed to local, transmission facilities with a return on equity adder, and enhancing interregional and state-to-state coordination to allow cost allocation for projects that have multi-regional benefits. Finally, FERC seeks comment on whether increasing the formal coordination between the regional transmission planning and cost allocation and generator interconnection processes—including concurrent and coordinated planning timeframes, co-optimization, and regional upgrade analyses—would lower rates for consumers and make costs more predictable for generators.

Second, FERC contemplates a series of reforms to the identification and allocation of costs in regional transmission planning and interconnection network upgrades to ensure that costs are allocated to beneficiaries in a manner corresponding to their estimated benefit. For transmission facilities, FERC suggests that a broader set of transmission benefits should be analyzed and accounted for collectively and not segmented into reliability, economics, and public policy planning benefits. FERC is particularly interested in comments that address the identification and allocation of benefits to beneficiaries that are difficult to quantify—either technically or because they span multiple regions. The ANOPR also seeks comments addressing to what extent changes in transmission planning and beneficiary identification might reduce the free-rider problem for future interconnection customers under the participant funding model.

FERC’s proposed reforms with respect to generation interconnection are designed to facilitate the on-going resource mix transformation by reducing cost barriers to interconnection. The ANOPR seeks comment on whether the participant funding model is a barrier that should be eliminated in competitive market regions and replaced with the crediting policy currently used in non-competitive regions. In the crediting policy, generators still pay for the interconnection network upgrades upfront, but receive transmission service credits that offset the service the generator takes from the transmission provider to recover the upgrade costs over up to twenty years. FERC seeks comment on whether the transition from participant funding to crediting policy would reduce cost uncertainty, queue backlogs, and the incentive to submit multiple speculative interconnection requests.

The ANOPR proposes several reforms to the crediting policy that could be implemented independently or in tandem, including: eliminating a generator’s upfront payment requirement and forcing transmission providers to pay for network upgrades, then allowing transmission providers to earn a return on the costs through their rates as they do for other facilities; requiring transmission providers to provide upfront funding for facilities above a certain voltage level because the higher voltage level may indicate a project will have multiple long term beneficiaries, while generators would still fund facilities below the set voltage level and receive transmission service credits; and allocating funding responsibility between the generator and transmission provider on a percentage basis. FERC also seeks comment on requiring generators to pay a non-refundable fee for each interconnection request that partially offsets the network upgrade cost. The fee could be fixed or variable depending on the capacity of the project, and could be charged upfront or gradually imposed as a project progress. Finally, the ANOPR seeks comment on several non-monetary reforms to the generator interconnection process including: limiting the number of requests permitted by a single generator or imposing a penalty for speculative requests; fast tracking interconnection requests for projects committed to regional transmission facilities; fast tracking “ready” generation projects that have an executed power purchase agreement or have been selected through a state or utility request for proposal; and the treatment of grid-enhancing technologies in interconnection request studies.

Third, FERC seeks comments on enhancing the oversight and transparency of transmission planning and costs. The ANOPR contemplates establishing an independent transmission monitor for each transmission planning region with various responsibilities including monitoring spending, scrutinizing development plans, developing cost benchmarks, evaluating planning decisions, and referring issues directly to FERC. Independent monitors would provide objective and transparent analysis of the transmission planning process to ensure that rates remain just and reasonable. FERC is asking for comments on how such a monitor could function in practice, how the monitor’s decisions could be reviewed, and whether FERC has the authority to create such an entity. FERC also requests comments on whether state commissions should be given a greater oversight and coordination role in the transmission planning process and setting limits on transmission owners’ ability to recover the costs of abandoned projects.

The ANOPR is just the first step in what is likely to be a multi-year regulatory process. Comments are due 75 days after publication in the Federal Register and reply comments are due 30 days after the initial comment deadline. Then FERC must draft a notice of proposed rulemaking and take more comments. Finally, FERC has to draft a final rule, address requests for rehearing, and give transmission providers time to implement any changes to their processes. The proposals outlined in the ANOPR are ambitious and not only represent a procedural overhaul of transmission planning and generator interconnection, but also a potential expansion of FERC’s authority. Stakeholders from across the sector will be interested in any changes coming out of the rulemaking, and because cost allocation is a zero-sum game, there is an inherent tension between reducing costs for generators and protecting rate-payers. Moreover, with very limited exceptions, state regulatory bodies have the ultimate authority over the siting and permitting of  transmission facilities, limiting FERC’s ability to spur increased investment unilaterally. The rejection of the Transource Independent Energy Connection project by the Pennsylvania Public Utility Commission is a recent example of the power of state regulators to thwart regional transmission planning. The 45-mile, 230 kV transmission line in Pennsylvania and Maryland was identified by PJM as necessary to relieve a transmission bottleneck in northern Maryland, and Transource was selected as the contractor in 2016. Construction of the project was supposed to have begun in 2019, but vocal local opposition in both states delayed the permitting process by several years until the Pennsylvania PUC unanimously rejected the project in May.

*Jacob Silver, 2021 Summer Associate, contributed to this article.