Interconnection is one of the most important aspects for deployment of clean energy projects. Every grid-tied project goes through an interconnection process and delays affect projects of all sizes. Interconnection reforms are undergoing review at two jurisdictions: The Federal Energy Regulatory Commission (FERC) and PJM Interconnection, a regional transmission organization that coordinates the movement of wholesale electricity within 13 states and the District of Columbia.
On January 24, CCEBA welcomed two attorneys from Clark Hill Law Firm – Dan Simon and Steven Shparber – to brief our members on the FERC Notice of Proposed Rulemaking (NOPR) and the PJM Interconnection Reforms, and what will be forthcoming from these actions. This blog is a report on the presentation, and should not be considered legal advice from CCEBA or from Clark Hill. Readers with specific questions should contact legal counsel for further information.
In 2003, FERC adopted Order Number 2003, which required utilities to adopt interconnection procedures and a standard interconnection agreement for all generators with more than 20 MW. The vast majority of interconnection providers have to use the FERC rules, but there are some exceptions. That order also specified that the generator is responsible for the costs at the site of interconnection and any transmission system upgrades to accommodate the project must be funded by the generator. The transmission provider then refunds the amounts paid by the generator during the five years following commercial operation of the generator.
FERC has reformed its rulemaking many times since 2003. In 2022, FERC proposed new reforms through the currently pending NOPR; a final rule is expected to be issued in 2023. Why did FERC propose this latest set of reforms? The goals for the changes include:
- To address interconnection queue backlogs caused primarily by the growth in renewables
- To improve certainty for interconnection timing and costs
- To prevent undue discrimination for new technologies (including energy storage on the generator side and transmission upgrades for customers themselves)
The reforms are detailed below.
One of the biggest changes in the FERC NOPR is the shift from a “first come, first served” serial process to a “first ready, first served” cluster study process. This transition is similar to reforms already undertaken by Duke Energy and Dominion Energy in the Carolinas. Under the reform, there will be more obligations on the interconnection customer to ensure that a project is ready to move forward. The cluster process involves considering many interconnection requests together. Interconnection customers have to demonstrate site control for their proposed generating facilities when they submit their interconnection request. Withdrawal penalties increase with each phase. By requiring stricter readiness standards, deposits at various “decision points,” and withdrawal penalties, the new process is designed to increase project readiness, reduce late withdrawals, and require fewer restudies. In addition, network upgrade costs will no longer be the single responsibility of one generator, but many together because it will benefit interconnection customers in later clusters.
Require Transmission Providers to Move Faster
The second aspect of the FERC NOPR is increasing the speed at which transmission providers process interconnection requests. These obligations, which will help renewable energy developers, includes everything from imposing firm study deadlines and making clear any affected system flagged for the interconnection procedure. FERC also increased the speed at which transmission providers must process interconnection requests. While the penalty amounts are quite small for violations, it will provide some incentive, and the NOPR itself is a clear statement of public policy urging faster interconnection and review of affected systems costs.
Flexibility for New Technologies
The NOPR increases flexibility for generators to use new technologies such as energy storage as a resource in an interconnection request and encourages transmission technologies that may be available in lieu of expensive network upgrades. The NOPR requires transmission providers to allow co-location of generation and storage behind a single point of interconnection with a single interconnection request. It also requires transmission providers to evaluate the proposed addition of a generating facility to an interconnection request provided it does not change the requested interconnection service level.
To date, transmission providers vary in their understanding and application of the concept of “material modification.” A material modification to a project is one that materially and adversely impacts other projects lower in the queue. The result of a material modification to a project can be losing the project’s position in the queue entirely, causing losses and potential restudy delays. In the most stringent cases, some transmission providers have maintained that addition of storage to a generation project is a material modification. FERC’s NOPR encourages energy storage, as more interconnection customers want to add energy storage to an interconnection request. The NOPR establishes that the transmission provider must evaluate such a request within 60 days to determine if the addition changes the maximum injection rights. If not, then the addition is not a material modification, allowing more flexibility to interconnection customers to make changes within the interconnection process.
In sum, FERC is looking for clearer deadlines, more defined withdrawal penalties, and standardized agreements so that everyone knows ahead of time what their obligations are, especially for affected system upgrades. There will be more standardization of system rules with deadlines on everything from the timing of a study to construction agreements. These changes are designed to reduce time and uncertainty for interconnection customers by negotiating all these details up front, and to provide more certainty and fewer queue withdrawals to aid in utility interconnection and transmission planning.
Unlike the FERC NOPR, the PJM reforms are currently in effect. The changes were filed in June 2022, accepted by FERC in November 2022, and most provisions are effective as of January 3, 2023. This reform was a multi-year process on how to transition PJM interconnection queue to adding more renewables to the grid. The reforms are not just focused on process changes going forward, but also how to work through the existing interconnection backlog in PJM’s territory. The reforms garnered mixed reviews from stakeholders in the renewable energy industry, but CCEBA believes they are, for the most part, better than the status quo.
Just like the FERC NOPR, the PJM reforms move from a “first come, first served” serial process to “first ready, first served” cluster approach with “decision points” project developers must meet such as from readiness deposits. The cluster process borrows heavily from the reforms in MISO and it aligns largely with the FERC NOPR. There are different queue cycles and there are cluster studies and project developers will have different decision points and different amounts of readiness deposits to move forward. The readiness deposits are done to make projects drop off early in the process rather than later.
The PJM reforms, somewhat controversially, require 100% site control, including gen-tie lines, and more site control evaluations at all decision points. Network upgrade cost analysis of individual projects is streamlined by clustering projects in the same cycle and proposed changes reduce restudies when projects are changed. Projects that do not contribute to the need for network upgrades and/or don’t need further studies will be able to proceed more quickly to a final interconnection agreement.
The effect of the PJM reforms on any particular project is highly dependent on where in the queue that project currently is. Which new transition cycle a given project falls into is a technical determination based not only on what cluster the project is in, but the readiness status of the individual project. For instance, a project in cluster AD2 or earlier would not fall into the transition period rules. However, a project in clusters AE1, AE2, AF1, AF2, AG1, AG2 and AH1 will fall into a transition cycle.
Some projects that fall into the cycle and receive a retool analysis may be able to receive expedited review if that analysis shows less than $5 Million in upgrade costs are needed. All of these determinations are highly site and project-specific. The figure below is taken from the PJM reforms and shows generally how different clusters are evaluated going forward:
Summary and Next Steps
While both the FERC NOPR and the PJM Reforms attempt to address interconnection backlogs, they do not address all of the issues facing interconnection customers. Crucially, neither addresses the critical need for interregional transmission planning reform. CCEBA argued, with some success, for transmission planning reform as part of the North Carolina Carbon Plan process and continues to represent the industry before the Commission and the Transmission Planning Cooperative.
FERC is expected to issue another NOPR on interregional transmission in 2023. New FERC Chairman Phillips has identified transmission as a key priority. CCEBA hopes FERC will address methods for incentivizing better interregional planning. It is difficult to have significantly improved interconnection queues that can connect renewable energy resources on the required scale without better transmission planning. In addition, FERC should also address the thorny issue of payment for network upgrades: Who pays for and who benefits from needed network upgrades, particularly transmission upgrades? In ERCOT, for instance, most upgrades are socialized and upgrade planning is known in advance, allowing renewable energy generators better cost transparency. Other jurisdictions, mindful of retail customer costs, have resisted such socialization.
Stay tuned to our updates on how the FERC NOPR moves forward. These are detailed and important policy decisions that matter for putting more renewables on the grid and improving reliability generally.