Interconnection Constraints Threaten Success of Clean Energy Projects

Power projects are filled with risk. One of the biggest risks today for clean energy developers involves interconnection constraints. And according to Sarp Ozkan, vice president of Commercial Product at Enverus, an energy-specialized technology provider, this could be a key risk for the foreseeable future.

Before a power project can come online, its interconnection with the power grid must be studied by the grid operator to identify transmission infrastructure upgrades needed to accommodate the project and allocate those upgrade costs to developers. Most interconnection queues have huge backlogs and the review process can result in years-long delays.

“In essence, projects are all queued up with nowhere to go,” Ozkan told POWER. “Our grid is too old and fragile to handle the onslaught of renewables that it is being asked to integrate into its generation mix. Thus, most interconnection agreements end up requiring significant, and often economics-crushing, grid upgrade requirements often after years of arduous and costly feasibility and study stages.”

IRA Amplifies Grid Challenges

The Inflation Reduction Act (IRA) included roughly $369 billion in incentives for energy and climate-related programs. Many power industry observers have praised the bill for the effect it could have on the clean energy transition. For example, the Bipartisan Policy Center, a not-for-profit organization that works to bring Republicans and Democrats together on issues, has said the clean energy provisions in the IRA will “accelerate the deployment of clean energy technologies, reduce global emissions, lower energy prices, help export American innovation, strengthen [the U.S.] economy, and build a reliable and affordable energy sector.”

Among the provisions contained in the IRA are expansions and extensions of several Production Tax Credits (PTCs) and Investment Tax Credits (ITCs). The thing that is notably missing from the IRA, according to Ozkan, is support for the revitalization and reimagining of the grid. “Since the credits target generation, the capital is incentivized to shift evermore towards renewable generation and storage, increasing the strain on the queues and the grid,” he said.

Ozkan said project queues are bloated. “In ERCOT [Electric Reliability Council of Texas], for example, all you need is land control, a single-line diagram, and $7,000 to enter the interconnection queue. The low bar to entry into queues has caused some of this bloating,” he explained.

What eventually determines if a project makes it to commercial operations, however, is the ability to interconnect with the grid. “Many developers do not spend enough time understanding the dynamics of grid congestion and available transmission capacity in their siting exercises. More thorough study of these risks as a part of the siting process is key to increasing the likelihood of eventual project success,” Ozkan said.

PJM Study Confirms Difficulties

A report published in May by the Natural Resources Defense Council (NRDC), an international nonprofit environmental organization, substantiates much of what Ozkan has said. NRDC researchers focused specifically on the situation in the PJM Interconnection, the largest grid operator in the U.S. PJM launched a stakeholder process in 2020 to revamp its interconnection queue, clear the backlog, and prevent future delays. Stakeholders agreed on a plan that was approved in 2022. Nonetheless, the NRDC study found that even under ongoing reform proposals, the pace of development in PJM “will just barely provide enough renewable energy to meet aggregate RPS [renewable portfolio standard] demand through 2027; states with the most ambitious RPS targets are likely to lack adequate supply to meet their demand starting before 2027.”

The NRDC’s analysis purportedly represents “the best-case scenario” in several key ways. First, PJM’s new approach will not be rolled out until 2026, which means PJM will likely be facing an onslaught of IRA-incentivized new renewable projects that could cause delays beyond what the researchers estimated. Second, current RPS data represents only “the bare minimum of renewable energy demand.” The report says there is “a clear trend toward RPS expansion and policy updates.” Third, the long implementation timeline of the queue reforms also prolongs investment uncertainty for renewable developers, who are reportedly facing skyrocketing costs already. “These factors may lead to much-needed new renewable generation being delayed, not developed at all, or unable to take advantage of new incentives under the IRA,” the report says.

According to the report, there were more than 202 GW of renewable energy resources waiting in the PJM queue as of September 2022. That accounted for more than 95% of the total queue. For context, there were only about 200 GW of clean energy resources operating in the entire U.S. in 2021. “There is little doubt that RPS targets and broader policy goals will be constrained by the speed and efficiency of the interconnection queue. Moreover, PJM Interconnection queue delays are symptomatic of broader issues with the antiquated systems for planning generation and transmission in the region,” the report says.

The Majority of Projects Will Be Abandoned

“For utilities, it is quite simple. Their grid is the biggest risk. Aging grids and ever lower spending on maintenance continue to be the critical point of weakness. The utility model doesn’t lend itself to spend on this weakness, which exacerbates the risk,” said Ozkan.

Given that grid issues are pervasive, it stands to reason that planned clean energy projects across the country are vulnerable to postponement or cancelation. “We do see the solar, wind, and storage project queues across the ISOs [independent system operators] have more capacity than can be supported by the grid or by demand moving forward. Thus, we should continue to see approximately 80% of the projects in the queue eventually getting suspended,” Ozkan concluded.

Aaron Larson is POWER’s executive editor.

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