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Breaking down the FERC interconnection NOPR

FERC has proposed large-scale changes to generator interconnection procedures based on comments received from stakeholders last fall.
Editor’s note: This is the first installment of a three-part series on the FERC interconnection NOPR. Parts 2 and 3 will examine proposed reforms to interconnection studies and queue processing.

FERC has proposed large-scale changes to generator interconnection procedures based on comments received from stakeholders last fall.

There are many details in this proposed rulemaking because FERC is seeking comments on fines imposed on transmission providers for interconnection study delays and penalties on interconnection customers if they withdraw before executing the interconnection agreement.

Transmission provider comments are due after 100 days of publication in the federal register.

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Listen to the latest episode, on shaping the grid of the future to support renewable energy, featuring Jim Walsh, GE’s head of grid software. This special edition of the Factor This! podcast was recorded live from DISTRIBUTECH and POWERGEN International in Dallas last May.

BackgroundPictured is Enel Green Power’s Chisholm View wind farm, one of the company’s now 13 wind farms in the state of Oklahoma. (Courtesy: Enel)

Picking up where it left off last October with the Advance Notice Of Proposed Rulemaking (ANOPR) on transmission planning and generator interconnection, FERC released a NOPR on June 16 specific to generator interconnection procedures. This “Improvements to Generator Interconnection Procedures and Agreements” is the most comprehensive NOPR from FERC related to the interconnection studies because FERC didn’t leave out any details, including assumptions made in study models.

FERC aimed at providing informational studies to renewable developers to reduce the speculative projects in the queues. FERC proposes to impose fines on transmission providers and renewable developers if studies are delayed and developers quit in later study stages, causing restudies. Taking the cue from recent PJM stakeholder discussions on the transition process, FERC even outlined steps to transition existing interconnection customers in different serial study stages to the new cluster-based process.

There are three parts to FERC’s interconnection NOPR. In part one, FERC proposed reforms to implement the first-ready, first-served cluster study process. In part two, recognizing the delays associated with affected systems studies, FERC proposed reforms to increase the speed of interconnection queue processing. And finally, FERC acknowledged the role of technological advancements in renewable interconnections and proposed to increase flexibility in the interconnection studies, including the adoption of grid enhancing technologies and setting modeling and performance requirements for studying renewable generation.

This blog discusses part one. Parts two and three are summarized in succeeding blogs.

Perspective: Enel weighs impact of FERC’s interconnection reform plan

First ready, first served

PJM is transitioning from a first-come, first-served serial study process to a first-ready, first-served cluster study process. Transmission providers serially studying interconnection requests made sense when there were tens or hundreds of requests but doesn’t with thousands of requests filling queues today.

The cluster study process is what MISO (Definitive Planning Phase DPP process) and SPP (Definitive Interconnection System Impact Study DISIS process) have adopted. By proposing reforms to implement the first-ready, first-served cluster process, FERC is standardizing the best practices based on MISO and SPP experience.

1. Interconnection information access

A key step for renewable developers is information on where to interconnect on the transmission grid for better network access.

Since a transmission provider holds all the modeling cards close to their chest with access to modeling data and assumptions, developers have a tough time predicting network upgrade costs with their interconnection requests. That lack of information led to multiple projects in the same county leading to the current large volume of queue requests. FERC aimed at this problem by providing developers an opportunity to request a prospective study in this NOPR.

Recognizing that some developers might abuse this informational study process and further bog down the transmission provider, FERC proposes limiting five studies at a time per interconnection customer in a cycle. FERC proposed that the informational interconnection study would be at the interconnection customer’s expense, and each study would require a $10,000 deposit, subject to a true-up based on actual study costs.

FERC is seeking comment on whether transmission providers should be required to establish a request window of a limited number of days each year in which potential interconnection customers can request an optional informational interconnection study.

FERC also recognized that developers need a “heat map” of locations with incremental transmission capacity to interconnect renewable projects. FERC called out MISO’s Point Of Interconnection (POI) map as an example of this heat map.  

2. Cluster study

In a serial-based study process, queue numbers matter because an interconnection customer with a number ahead of others is studied first. However, a cluster-based process eliminates the headaches with queue numbers by assigning all requests received before the cluster window close date the same queue priority. FERC proposes a “cluster study agreement” that ensures interconnection customers are studied only for a point of interconnection (not multiple locations, unlike a serial study process). FERC proposed that the transmission provider post all requests to be studied as part of that cluster on its website. This process happens at MISO with its DPP and SPP with DISIS cluster studies.

FERC is seeking comment on whether transmission providers should be required to study subgroups of interconnection customers based on geographic location and electric transmission relevance. FERC is also seeking comment on whether the transmission provider should be limited to two re-studies per month in a 150-day cluster restudy period.

3. Allocation of cluster study costs Pine Gate Renewables’ Collier Solar project in Bend, Oregon. (Photo: Business Wire)

FERC is cognizant that multiple re-studies are killing the efficiency of cluster studies because each time a developer quits the queue, the transmission provider must conduct a restudy to determine the network upgrades and who pays.

Hence, FERC proposed 90% of the applicable study costs to interconnection customers on a pro-rata basis based on requested MWs included in the applicable cluster and 10% of the applicable study costs to interconnection customers on a per capita basis based on the number of interconnection requests included in the applicable cluster. And FERC is seeking comment on whether a different cost allocation approach is needed or whether each transmission provider should be provided additional flexibility to propose a cost allocation approach.

4. Allocation of cluster network upgrade costs

There is a reason behind the clustering process: who pays and how much they pay for the transmission upgrades needed to accommodate that cluster MW amount. The transmission provider assigns costs based on the impact of the customer’s requested MW amount. Recognizing this MW impact, FERC proposes requiring transmission providers to allocate network upgrade costs to interconnection customers within a cluster using a proportional impact method.

FERC is seeking comment on the specifics of the proportional impact method. Are there any benefits and drawbacks of this method? Is there any specific analysis that is most suitable for assigning network upgrade costs in a cluster? And how should the transmission provider deal with clusters in small service areas?

5. Shared network upgrades Transmission lines outside Houston, Texas (Courtesy: BFS Man/Flickr)

FERC also recognized that network upgrades paid by interconnection customers in one cluster could impact developers in succeeding clusters. For example, if an interconnection customer paid for a $10 million upgrade in MISO’s 2020 DPP cycle, a developer in MISO’s 2021 DPP cycle could benefit from that upgrade when connecting at the same location. Developers share network upgrade costs in a cluster. That is not the news here. The news is how to allocate shared network upgrade costs across clusters.

FERC has proposed that the transmission provider evaluate all network upgrades identified in the study process, including if a generating facility of an interconnection customer in a later cluster study directly connects either to (1) a network upgrade in-service for less than five years or (2) a substation where the network upgrade in-service for less than five years terminates, then the transmission provider would be required to designate the network upgrade a shared network upgrade.

Once a shared network upgrade is found, the interconnection customer in the later cluster study would be required to contribute a pro-rata portion of the shared network upgrade’s remaining capital cost based on the impact the interconnection customer in the later cluster study has on the network upgrade as measured using the same method the transmission provider used to determine the impact of the interconnection customer(s) in the earlier cluster study.

If the new generating facility does not directly connect to the network upgrade, FERC proposed that the transmission provider perform a power flow analysis with a two-step test to measure the later-in-time interconnection customer’s use and benefit from the network upgrade funded by interconnection customers from an earlier cluster study. FERC is largely adopting MISO’s 20% Transfer Distribution Factor (TDF) screening process to evaluate when network upgrades across clusters will be shared.

FERC proposed interconnection customers pay transmission providers a one-time lump sum payment for their share of the network upgrade costs. An added nuance is that FERC proposed that the interconnection customer does not pay for its share of the network upgrade until it is in service.

6. Increased financial commitments and readiness requirements

Taking the collective experiences of MISO and SPP interconnection procedures, FERC is proposing this study deposit framework – for projects greater than 20 MW and less than 80 MW – a $35,000 study deposit plus $1,000 per MW, for projects greater than 80 MW and less than 200 MW – a $150,000 study deposit, and finally for projects greater than 200 MW – a $250,000 deposit. FERC proposed that the transmission providers collect these study deposits before each phase of the study process.

These study deposits are refundable, but as developers attest in MISO and SPP queues, they must withdraw before the start of the next study phase. Otherwise, they risk the entire deposit. To detest less serious developers, FERC also requires interconnection customers to submit a deposit equal to nine times the amount of its study deposit when executing the Large Generator Interconnection Agreement (LGIA) or requesting the filing of an unexecuted LGIA.

On site control, FERC found that an interconnection customer securing the exclusive land right necessary to construct its proposed generating facility (or for co-located resources, demonstration of shared land use) is sufficient evidence of the interconnection customer’s commitment to construct the generating facility. To cut down on multiple interconnection customers leasing the same site to remain in the queue, FERC proposed to require interconnection customers to demonstrate the exclusive land right (where the land rights are exclusive to the interconnection customer, not necessarily the individual project) to develop, construct, operate, and maintain its generating facility or, where facilities are co-located, to demonstrate a shared land use right.

For situations where regulatory limitations prohibit demonstration of site control, FERC proposed interconnection customers submit an initial deposit instead of site control of $10,000 per MW, subject to a floor of $500,000 and a ceiling of $2,000,000, which would be applied toward any interconnection studies or withdrawal penalty. FERC is seeking comments on all aspects of this site control.

For commercial readiness, FERC took lessons learned from transmission providers outside organized markets in the Western and Eastern Interconnect (PSCo, PacifiCorp, Tri-State, Dominion, and Duke) and proposed options to demonstrate commercial readiness, such as executed contract (as opposed to term sheet), binding upon the parties to the contract, for sale of (1) the constructed generating facility, (2) the generating facility’s energy or capacity, or (3) the generating facility’s ancillary services; where the term of sale is not less than five years.

FERC also proposed a commercial readiness deposit (in addition to a study deposit) instead of meeting commercial readiness requirements in the following amounts:
• Two times the study deposit amount to enter the initial cluster study phase;
• Five times the study deposit amount after the initial cluster study phase and before the system impact restudy phase; and
• Seven times the study deposit after receipt of the facilities study agreement

Finally, FERC proposed stringent withdrawal penalties in this NOPR to reduce the restudies. FERC proposed (1) two times the study cost if the customer withdraws during the cluster study or after receipt of a cluster study report, capped at $1,000,000; (2) three times the study cost if the customer withdraws during the cluster restudy or after receipt of any applicable restudy reports, capped at $1,500,000; (3) five times the study cost if the customer withdraws during the facilities study, after receipt of the individual facilities study report, or after receipt of the draft LGIA, capped at $2,000,000; or (4) nine times the study costs if the customer withdraws before achieving commercial operation and after executing the LGIA or filing an unexecuted LGIA.

FERC is seeking comments on whether it should consider exceptions to the withdrawal penalties.

7. Transition processFederal Energy Regulatory Commission

Since these proposed requirements are a big change, FERC requires transmission providers to offer existing eligible interconnection customers the options, for each project in the queue, to either enter a transitional serial interconnection facilities study or a transitional cluster study with commercial readiness requirements or to permit them to withdraw from the interconnection queue without penalty.

FERC proposed a transitional serial study for eligible interconnection customers that requires executing a transitional serial interconnection facilities study agreement to hold developers accountable. The transitional serial study withdrawal penalty would equal nine times the study cost because all future interconnection requests may be harmed if the transitional projects do not reach commercial operation. FERC recognized that these transitional projects would be included in the base case of the transitional cluster study, so a transitional serial project withdrawal could cause the entire first cluster to be restudied.

Interconnection customers also have the choice to request a transitional cluster study, not just a serial study. FERC proposes a $5 million deposit to ensure that interconnection customers are ready to move forward. FERC is seeking comments on this transition process, including the $5 million deposit required for the transitional cluster study process.

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