Improvements to Generator Interconnection )
Procedures and Agreements                             ) Docket No. RM22-14-000

Initial Comments of the R Street Institute

I. Issue Summary

On July 27, 2021, the Federal Energy Regulatory Commission (Commission) published an Advance Notice of Proposed Rulemaking (ANOPR) on potential reforms to improve generator interconnection processes, regional transmission planning and cost allocation. On July 5, 2022, the Commission published a Notice of Proposed Rulemaking (NOPR) on improvements to generator interconnection procedures and agreements. The intent of the NOPR is to address interconnection queue backlogs, improve certainty and prevent undue discrimination of new technologies. To ensure that the large generator interconnection (GI) process is not unduly discriminatory or preferential, the NOPR requires public utility transmission providers (TPs) to adopt an interconnection cluster study process, cost allocation for cluster studies, increased financial commitments and more readiness requirements. The NOPR also proposes reforms aimed at increasing interconnection queue processing and incorporating technological advancements into the interconnection process.

II. Summary of R Street Position

The R Street Institute (RSI) filed initial and reply comments in the ANOPR. 3 RSI hereby submits overarching comments on the need for a vision of GI reform as well as comments specific to the prompts in the NOPR.

The NOPR does not elucidate a holistic problem statement, nor paint a clear vision of the objectives of GI reform in complete context. Doing so is imperative to any reform strategy, especially given the co-dependencies of GI reform on regional transmission reform and resource adequacy constructs. As such, RSI offers a problem statement and vision of GI reform.

GI processes are necessary, but their current form imposes excessive systemwide costs and large undue barriers to entry for new resources, which results in unjust and unreasonable rates under the Federal Power Act. Deep-seated flaws, such as deliverability requirements for a network resource, combined with cost allocation, information access and procedural problems, were once marginal. Now these flaws are major unavoidable problems. Flaws in GI processes are particularly exposed given the number and type of GI requests under the new generation paradigm.

This is causing a “massive backlog and delay in the construction of new power projects.” At the end of 2021, over 1,000 gigawatts (GW) of generation capacity was in interconnection queues. This is almost the capacity of the entire existing U.S. generation fleet, which measures 1,144 GW. The average wait time in queues has increased from 2.1 years to 3.7 years from projects built in 2000-2010 compared to projects built in 2011-2021.

Delays are expected to worsen under prevailing market conditions and with the passage of the Inflation Reduction Act (IRA). Industry routinely cites permitting and interconnection-related problems as the largest barriers to entry today. For example, a 2021 survey found 89 percent of developers citing “interconnection timelines and costs” as the biggest barrier to entry for solar deployment.

The problem is not merely the result of greater GI request volume, but also the nature of projects seeking interconnection. Current GI processes are vestiges of the “open access” transmission model for vertically integrated utilities constructing thermal power plants. Now, renewables are dominating interconnection requests with independent power producers developing five times more wind power and eight times more solar power than monopoly utilities. Unlike conventional thermal plants, in which the beneficiary of transmission upgrades predominately accrues to a single generator, the benefits of transmission upgrades are increasingly dispersed. The incremental transmission upgrade approach in current GI processes can increase upgrade costs by multiples, increasing uncertainty and total costs by tens of billions of dollars per region, while causing underinvestment in upgrades because those paying for the upgrades do not receive many of the benefits. GI processes therefore impose greater unnecessary systemwide costs and depart from beneficiary-pays upgrade cost allocation with the evolving resource mix, in addition to erecting barriers to entry that disrupts an orderly, efficient and reliable energy transition.

An examination of the causes of GI delays shed light on the root problems. These manifest as barriers to entry in three forms:

GI reform can result in drastically lower transmission upgrade costs and barriers to entry while still achieving the objectives of current GI processes. The purpose of GI procedures is important, but some functions of current GI processes best reside in other processes. For example, RSI recommends merging aspects of GI that trigger network upgrades into proactive transmission planning in order to co-optimize system planning while lowering transactions costs, uncertainties, duplication and inconsistencies between interconnection and transmission planning processes. Overall, optimal GI reform is highly co-dependent with transmission policy and resource adequacy constructs, which are undergoing their own reforms concurrently.

Consistent with our regional transmission planning reform comments, transmission network upgrades could shift entirely to regional transmission expansion planning. Generation assumptions could be informed by generator requests, perhaps in a format similar to the open season processes for pipeline expansion. A short-term transmission planning process could readily respond to upgrade requests and feed into the long-term planning process. Cost allocation should still follow the beneficiary pays principle. Implementation methods may include calculating generator benefits by expected increases in wholesale market revenues and consumer benefits calculated by wholesale rate reductions and the value of avoided lost load.

Removing transmission network upgrade studies from GI would markedly reduce GI technical and administrative requirements, enabling a far simpler interconnection process. This could result in energy resource interconnection service (ERIS) serving as a simple service when it comes to requirements for reliability, reactive power capability, transformers, protection, control and communications. Generators could fund and own ERIS and request transmission upgrades in the transmission expansion process. Network resource interconnection service (NRIS) could be marginalized, redefined or eliminated. ERIS has the advantage of not having the demanding and inaccurate deliverability tests and requirements of NRIS and would greatly reduce the transmission investment needed for local interconnection. Network Integration Transmission Service (NITS) could be simplified and redefined to focus RTOs on efficient generator dispatch.

The deliverability requirements of interconnection for NRIS are tethered to the resource adequacy construct. The definition of deliverability and associated procedures are often unclear and vary by region, which limits prescriptive pro forma tariff reforms to GI. Improving the deliverability construct is important for resource adequacy as well as GI. Currently, GI for NRIS and capacity accreditation processes presume centralized administrative modeling is capable of accurately determining, years in advance, what generation can meet particular load needs. This false premise introduces extensive administrative uncertainty that translates into system performance risk. This can be addressed in part by shifting performance risk onto generators and away from permission-based administrative processes. Aligning generator financial incentives with performance includes foregone energy and ancillary service revenues as well as foregone capacity revenues or performance penalties. Ensuring generators bear the risk of curtailment and nonperformance losses and/or penalties can be used in exchange for eliminating or drastically reducing deliverability test requirements. With sufficient information on risk drivers, generators have proven capable of managing such risks.

The Electric Reliability Council of Texas (ERCOT) provides a worthwhile case study. Industry experts consider ERCOT’s GI process to be perhaps the most effective domestically. Projects can be developed and interconnected in the ERCOT footprint in 2-3 years, whereas the interconnection study alone takes that long in some other regions.

ERCOT uses a “connect-and-manage” GI approach, in which transmission network upgrades in ERCOT are handled in the transmission planning process and GI does not include deliverability requirements. This contrasts with other RTO’s “invest-and-connect” GI approach. The ERCOT approach places siting risk on generators, who account for congestion and curtailment risk. This results in a simple GI process with far lower barriers to entry. Transmission upgrades respond to systemwide curtailment and congestion, such as those recently developing in the Texas panhandle area, via the transmission planning process.

ERCOT’s core role is informing rather than gatekeeping. Better information, such as on generator export ability, improves generator and resulting system risk management. The GI process has two parts: a screening study (SS) performed by ERCOT and a full interconnection study (FIS) performed by the transmission service provider. After a project requests a FIS, it is publicly listed in a monthly report detailing its capacity, technology, point of interconnection, county location and other factors. Pertinent milestone dates are also tracked and updated, such as FIS request and approval dates, data of interconnection agreement signed and milestones determining whether projects are included in planning models. This transparency helps evaluate and motivate performance; the SS is completed on average in less than 80 days.

The advantages of ERCOT’s transparency and treatment of transmission network upgrades is applicable to all regions. The simplicity advantages of not having a deliverability test may not be fully replicable in RTOs with capacity markets. Nevertheless, capacity market regions can still modify their deliverability and transmission service constructs to accommodate a GI and resource adequacy paradigm that puts greater performance risk on generators.

Overall, the NOPR needs to specify a comprehensive problem statement and a vision. As it stands, specific reforms proposed in the NOPR are incomplete and without larger context. What is missing most is how network upgrades triggered by GI requests today might be handled in transmission planning reform, as well as how to rectify the inefficiencies of varying deliverability tests across regions that depend on the Commission’s willingness to reconsider concepts like NRIS. The NOPR defines the floor for GI practices, but it does not frame the ceiling nor strive for it.

RSI encourages the Commission to describe a vision that harmonizes GI with transmission planning and resource adequacy requirements with the objective of minimizing system costs, realigning cost allocation with beneficiary pays and eliminating undue barriers to entry. The Commission should map detailed root causes of GI performance problems today to inform specific reforms (e.g., GI stage criteria). A more comprehensive reform agenda includes:

Prompted NOPR Comments Summary 

The prudence of the incremental reforms proposed in the NOPR are difficult to comment on in the absence of the context that a visionary roadmap provides. Nevertheless, RSI’s comments assume the proposed reforms are incremental under “business-as-usual” assumptions. The Commission should clarify that the overarching policy goal of pivoting TPs toward providing information and away from acting as permissive gatekeepers based on administrative assumptions of long-term deliverability.

The NOPR does not address all GI elements in need of reform, though it proposes many sound and some problematic reforms. Advancing a first-ready, first-served cluster process in which improved reporting and public interconnection information are paramount. But the Commission should remove other proposals in the NOPR that introduce barriers to entry and may adversely affect competitive relationships, such as those between incumbent utilities and independent power producers.

RSI provides the following major recommendations on the three main categorizations of proposed reforms in the NOPR:

1. Reforms to implement a first-ready, first-served cluster study process.

a. Require public interconnection information, such as heat maps of transmission capacity, in lieu of informational interconnection studies requirements.
b. Require a shift from sequential to cluster study GI process. Reductions in uncertainty, transactions costs and system costs are in the billions of dollars per region.
c. In lieu of static deposit levels, explore using a market-based mechanism that reflects the expressed willingness to pay of GI-requesting parties in a public reservation system. This would obfuscate the need for other proposed requirements.
d. Avoid site control and commercial readiness requirements that exacerbate barriers to entry by imposing schedule dependencies in project development. Some NOPR proposals are unworkable, including requiring full site control and an executed contract. They contradict the NOPR’s intent.

2. Reforms to increase the speed of interconnection queue processing.

a. Require TPs to provide refined reporting in lieu of levying penalties, which do not address root causes of delays. Public reporting should at least provide monthly GI request-specific progress, such as that conducted by ERCOT.
b. The Commission should convene stakeholders around identifying root causes of GI queue processing delays and best practices, such as optimizing study cycles and harnessing advances in automation and computing.

3. Reforms to incorporate technological advancements into the interconnection process.

a. Increase flexibility of GI processes to accommodate hybrid resources and require TPs to incorporate alternative transmission technologies into GI assessments.

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