PJM interconnection costs up in recent years, queue reform alone unlikely to fix

As PJM undertakes a reform process to modernize its interconnection queues to accommodate unprecedented amounts of new renewables looking to join the Mid-Atlantic’s grid, a new study from the Department of Energy’s Lawrence Berkeley National Laboratory spells out just how expensive the process became for developers in recent years.

The average interconnection costs for projects that have completed all interconnection studies in recent years doubled (USD 84 per kW) relative to projects completed between the years 2000 and 2019 (USD 42 per kW). The average for projects “still actively moving through the queue” rose from USD 29 per kW between 2017 and 2019 to USD 240 per kW between 2020 and 2022.

Abandoned projects have fared worse. Most recently they faced average interconnection costs of USD 599 per kW — “likely a key driver for those withdrawals,” the report said. Developers have also cited broadly unfavorable economic conditions, difficulty sourcing materials, supply chain disruptions, and more as key drivers for queue withdrawal.

Still, reforms are not likely to fix rising costs, at least not on their own, according to Dr. Joachim Seel, a Principal Scientific Engineering Associate at the Berkeley Laboratory’s Electricity Markets and Policy Department and one of the study’s authors.

“I don't think that it directly affects the determined integration costs,” Seel told NPM. “It may affect cost certainty, like early on, if lots of other projects that are supposed to either trigger other upgrades that you then have to pay for as developer partially, or who may help you finance part of the upgrades that you are triggering. And then ultimately, (if)those projects withdraw, that can change the numbers. But I don't think that anything has really been done in terms of cost allocation between … the old way that PJM was doing things and the new proposed way now. So, I don't think that the total magnitude of costs would really be different now.”

Without a broad rethinking of the issue, the problem is likely to persist even if PJM clears its bottleneck, as the industry and state governments move to fulfill renewable generation goals by the end of the decade.

Though PJM is paused to new applicants at the moment, trends in other RTOs and ISOs show “continued expansion” of new applicants, Seel said. Those are likely to trigger further upgrades to transmission. Whether those will be triggered and paid for by developers as they come or covered by “a more proactive, medium term planning approach” — as suggested by FERC’s Regional Planning Transmission NOPR — “it remains to be seen,” he said.

In addition to upgrades kicked off by new interconnection requests, transmission investments can also come in the form of local reliability investments by transmission owners and longer-term transmission expansion plans, Seel said. Investments that come about from longer-term planning processes can alleviate the need for network upgrades, and therefore also lessen generators’ interconnection costs, he added.

“It is generally thought that such ‘proactive multi-value transmission planning’ is also much more economically efficient and cost-effective, as it is an integrated and not a siloed approach," Seel said. "Transmission investments under these longer-term plans are generally paid for by the ratepayers and not developers of new generators.”

Seel pointed to MISO's long-term transmission planning in 2022, featuring more than USD 10bn in investments in new transmission lines, as an example of “proactive planning.” As NPM reported following the MISO Board’s approval of the 18-project plan, the grid operator estimates the upgrades will allow for more than 50 GW of new renewables.

“In MISO, we've definitely seen a lot of new, larger transmission investments. If those would happen in a substantial way that probably then reduces the amount of network upgrades that are triggered by any individual request,” Seel said. “And I know that PJM is rethinking the way that they are doing the medium-term regional transmission planning, as well. But I don't think that that has been decided yet in the context of the queue reforms themselves.”

In October, the Laboratory released a similar study to the one released this week focused on PJM. For both grid operators, projects that ultimately withdraw face higher costs than others still active in the queue, but a study of MISO did not reveal a similar strong increase in those figures in recent years.

“In PJM, it seems that the recent cost escalation trend has been a little bit more pronounced than in MISO. But other than that, in both ISOs costs have gone up,” Seel said. “The costs have primarily (been) driven by broader network upgrades and not like local attachment facilities or point of interconnection costs.”

Across both grids, solar, wind and solar+storage projects have dealt with higher interconnection costs than natural gas projects, which have actually seen a drop in cost in recent years, Seel said. More studies are underway in SPP, NYISO and NEISO are on the way, and the Laboratory is working through their data analyses of these at the moment, Seel said.

Data transparency made their job particularly tedious. The report took some 550-man hours to collect and interpret from individual PDFs. This barrier makes it unlikely the Laboratory will undertake this study on an annual basis. But the issue might find champions in developers trying to determine whether they should enter the queue.

“So that I think is really a big information barrier, which makes it very difficult for new developers to really ascertain what interconnection costs may be if they propose in different parts of the country. And so I think PJM is trying to get at that with a new queue proposal with a new cluster data, (I heard) that they want to make some interconnection cost data then available digitally. But overall, this is still I think a major area of improvement.”

*This story was originally published exclusively for NPM subscribers last month.


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