FERC just unveiled its transmission rules. But more remains to be done.

The Inflation Reduction Act set out to accelerate renewable energy development through tax credits. But ironically, the flood of solar and storage projects chasing those credits has actually bottlenecked progress toward a cleaner grid. The reason? Persistent and systemic roadblocks to interconnection.

As of late 2023, renewable energy developers’ project queues have grown by nearly 12% to over 110 gigawatts — but that doesn’t mean that all those projects are coming online. In fact, the glut of requests has more than doubled interconnection wait times: the typical project completed in 2022 spent five years in the queue for approval, compared to three years in 2015 and under two years in 2008.

This week, the Federal Energy Regulatory Commission released its long-awaited transmission rules, which updated the way new lines are planned and paid for, and directed grid operators to plan for infrastructure needs 20 years in the future. This will mean that they must account for anticipated changes in the resource mix, and weigh long-term benefits as they consider building and upgrading lines.

It’s a major boon for the renewables sector, but a queue remains. To expedite it, it is essential to streamline processes and modernize systems, in order to ultimately mitigate financial risks and improve the grid’s stability. And this will be made easier by industry-wide cooperation between stakeholders aiming to accelerate the integration of renewables. 

A growing queue

Partially as a result of the queue, only one out of five clean energy proposals are actually built. 

For instance, PJM Interconnection, which operates the nation’s largest regional grid, froze new applications until 2026 to work through its thousands-deep backlog. And although California utilities are legally required to hold a scoping meeting within thirty days of receiving an interconnection application, the state’s backlog has extended that timeline to over a year. In some areas, interconnection wait times have reached up to a whopping eight years.

In an attempt to lower these waits, FERC recently approved a "first-ready, first-served" approach to interconnection projects, which prioritizes interconnection projects based on their readiness for grid integration. But on its own, this policy doesn’t fix the problem. Current FERC standards still require projects to be fully permitted and have power purchase agreements in place before interconnecting, and those processes consume months if not years. 

To secure permitting, developers must spend millions to prove project viability and costs. For instance, a developer could spend $1 million on permitting fees and sign a PPA, only to get mere 20-30 cents per watt interconnection costs afterwards. This may not be sufficient to cover the developer's expenses, let alone generate a reasonable return on investment.

This level of financial risk is too high for many developers to consider — especially considering that over the course of a few years, the IRA flood of renewable energy projects could oversupply the grid and drive down power prices. These lower prices would make it even harder for developers to profit long-term. For renewable energy developers and investors to move forward confidently, these ongoing roadblocks must be addressed.

ERCOT appears adept at progressing its queue through the “connect and manage” approach, enabling generators to interconnect quicker, more efficiently, and at a low cost compared to other regions in the country. The interconnection process typically takes about 3.5 years in ERCOT, whereas it often takes twice as long in other areas.

Addressing the backlog

Fortunately, we have options. 

First, federal, state, and local authorities should prioritize coordination to standardize and simplify the often-byzantine interconnection process. FERC took a major step in this direction on Monday, when it unveiled its strategy to expedite the construction of long-distance transmission lines, aiming to meet escalating power demands and integrate a backlog of scheduled clean energy projects into the grid. 

Since the maze of regulations that differ across jurisdictions is a major barrier to interconnection, streamlining permitting requirements via unified standards would help provide certainty upfront for developers — and allow authorities to pick up the pace of reviews.

Another crucial step for speeding up interconnection is having the federal government invest in transmission upgrades that add capacity and update old infrastructure. Adding capacity will make it easier to connect and distribute renewable generation, while improving outdated equipment will help it handle an increased load of distributed and utility-scale renewable projects. GETs, or grid-enhancing technologies, are designed to increase capacity and flexibility in existing systems. An RMI report found that GETs could facilitate the addition of over six GW of renewable projects by 2027, and save $1 billion in annual production costs.

Beyond investing in the grid itself, policymakers must also incentivize assets that bolster grid stability as more renewables come online. This includes expanding markets and programs that fairly compensate technologies like batteries and distributed energy resources for the many services they provide. 

For instance, rather than just arbitrage, batteries support the overall grid in vital ways including frequency regulation, peak management, and load shifting. Comprehensive incentives that account for such services will better reflect the full value they bring to the grid. By rewarding these benefits directly, utilities and governments can accelerate the renewable transition while ensuring more reliable, resilient electricity. 

A utility company, considering investing in a large-scale battery energy storage system, for instance, is further encouraged to do so when offered incentives that acknowledge the diverse capabilities of batteries.

Furthermore, local regulators that create fair incentives — be they financial or in the form of a streamlined permitting process — can help offset developers’ hesitations about the risk of investing in PPAs and project permitting in the face of interconnection uncertainties. 

These incentives can ensure stable returns, in addition to avoiding oversupply issues that would drive down power prices excessively. With this reassurance, renewable energy developers can proceed confidently knowing project risks will be capped.

Most importantly, stakeholders and regulators need to come together in constructive discussions on how to move forward, and on the lessons we can take from more successful markets such as the United Kingdom. Convening our best minds — from policymakers to developers, regulators to utilities — to address challenges and best practices will help unlock the IRA’s full potential of a cleaner, more resilient grid.

Thomas Houghton is the CEO at Adapture Renewables, a utility-scale solar and storage developer and operator. The opinions represented in this contributed article are solely those of the author, and do not reflect the views of Latitude Media or any of its staff.