Here are ways to connect clean energy projects to the grid more quickly

Canary Media’s Down to the Wire column tackles the more complicated challenges of decarbonizing our energy systems. Canary thanks CPower for its support of the column.

Clean energy projects are facing multiyear waiting lists and unreasonably high costs to interconnect to U.S. transmission grids — a well-known problem in the electricity sector. But what can be done about it?

That’s the question that brought members of the Federal Energy Regulatory Commission and state-level energy regulators from across the country together earlier this month. In an all-day session, the joint federal-state task force examined the causes of interconnection congestion as well as potential solutions.

Massive transmission backlogs have become a serious impediment to expanding clean energy and providing customers with reliable and low-cost electricity. Solutions are hard to come by, however. Over the past decade, the scale of the solar, wind and energy-storage projects being planned and built around the country has boomed. But the methods grid operators and utilities use to assess the impacts and costs of connecting these projects to the grid haven’t kept up.

Grid-impact studies conducted by the major regional transmission organizations and independent system operators, which manage the high-voltage grids providing electricity to about two-thirds of the American population, have become increasingly complicated. These studies determine how much developers will have to pay for upgrades to allow their projects to interconnect to the grid and deliver power.

“Studies are taking four or five years in some cases,” FERC Commissioner Willie Phillips said at this month’s meeting between FERC and members of the National Association of Regulatory Utility Commissioners (NARUC). ​“This is simply untenable.”

Interconnection reform has become an important piece of the broader transmission policy reform effort that FERC launched last year. FERC’s first big decision on this front came last month in the form of a proposal to revamp long-term regional grid planning. This could help expand grid capacity for more clean energy in the long run, and it has won support from NARUC for its inclusion of states in the decision-making process.

But in the meantime, FERC and state regulators need to explore more near-term solutions to the interconnection morass, according to industry advocacy groups American Clean Power Association, Advanced Energy Economy and the Solar Energy Industries Association. In a joint filing last year, these groups asked FERC to ​“take immediate steps to fix the acute procedural deficiencies and network upgrade funding problems plaguing the current interconnection process in many regions by initiating an accelerated, stand-alone interconnection rulemaking.”

FERC hasn’t laid out what it plans to focus on next in terms of its broader transmission reform effort. But how it chooses to approach interconnection reform could play a big part in determining whether the country can build out the hundreds of gigawatts of wind and solar power and batteries needed to meet state carbon-reduction mandates and decarbonize the grid quickly enough to mitigate the worst harms of climate change.

That makes interconnection reform a vital area in need of hard work and innovative approaches, no matter how horribly complicated and esoteric it might be. Here’s a breakdown of the current mess and how decision-makers could start to fix it.

The vicious cycle of interconnection delays and rising costs

Just how clogged up U.S. grids have become is laid out in an April report from Lawrence Berkeley National Laboratory. Between 2015 and 2021, energy projects seeking to interconnect to the transmission grids of the country’s seven major grid operators and 35 largest utilities have seen average wait times grow from about one and a half years to more than three and a half. In the past decade, only about 23 percent of all projects in interconnection queues have ultimately been able to plug into the grid and start operations.

One reason is the sheer number of projects in line. As of last year, a massive 1,300 gigawatts’ worth of solar, wind and battery projects were awaiting interconnection — technically enough to supply about 80 percent of the country’s electricity demand. This chart from the American Clean Power Association trade group lays out the current mix of resources queued up in different parts of the country.

That in itself is a problem, FERC Commissioner Mark Christie said during the meeting. Simply put, the amount of electricity seeking grid interconnection far exceeds demand across the country.

That doesn’t mean that energy developers actually intend to build this many projects, he emphasized. Instead, many projects in the queue are just ​“paper-holders,” or speculative claims on the transmission grid’s capacity, rather than projects ​“that have the financial wherewithal and the business plan to actually get built,” Christie said.

This surplus of speculative interconnection requests is both a response to and a cause of worsening interconnection delays, FERC’s Phillips said. Because it can take years between making an interconnection request and having it approved, energy developers feel they must submit multiple requests for projects they may not even have customers for yet. In other words, ​“they do this to snag a spot in line,” he said.

They also do it to figure out where they can afford to interconnect. As transmission grid buildouts have slowed over the past decade, project developers have been forced to cover more and more of the grid investments needed to allow new projects to come online.

FERC Chair Richard Glick said, ​“increasingly, transmission development is being done through the network upgrade process” — that is, by charging grid upgrades to interconnecting projects — ​“rather than through the traditional planning process.” Over the past five years, these interconnection upgrade costs have grown from about 10 percent of project costs to between 50 to 100 percent of the cost of actually building the wind or solar farms themselves, according to a 2021 analysis from consultancy Grid Strategies.

Project developers may not know how high those costs will be until years into the process — and more and more frequently, the upgrade costs that are ultimately levied can end up being ​“a deal-killer,” said Bryn Baker, senior director for policy innovation at the Clean Energy Buyers Association (CEBA) trade group.

At other times, lack of capacity can prevent new projects from even being considered in large portions of the grid. A CEBA member’s recent request for proposals to build a 100-megawatt wind farm in the northern region of the Midcontinent Independent System Operator’s territory received no submissions“because transmission congestion was preventing any developers from considering the area,” Baker said.

To avoid the risk of deal-killing upgrade costs, ​“generators are submitting multiple interconnection requests as a form of price discovery,” Phillips said, further clogging up interconnection queues. Then they withdraw projects that cost too much, forcing grid operators to re-study the projects that remain — as well as those that have been added to the queue in the intervening time — to see how they’ll affect the grid and what potential upgrades might be needed as a consequence.

This cascading set of interconnection requests and withdrawals, as well as the lengthy and complex studies required with each change in the mix of projects that remain in queues, has grown so overwhelming that some grid operators are seeking to halt the process until they can sort out their existing backlogs. Earlier this year, mid-Atlantic grid operator PJM proposed delaying new projects from entering its interconnection queue until 2025 in order to expedite about 1,200 projects still awaiting assessment.

How interconnection backlogs and never-ending assessments have made a mess of grid planning 

To make matters even more complicated, projects being proposed in one grid operator’s territory may be deemed to have an impact beyond its boundaries. To figure this out, neighboring grid operators conduct ​“affected-system studies” that can assess costs for grid upgrades that are hundreds of miles away.

These affected-system studies ​“have become a key contributor to the ballooning effect” on transmission queues and interconnection costs, Gizelle Wray, senior director of regulatory affairs for the Solar Energy Industries Association, said in a February interview.

In a recent report, clean-energy developer Enel Green Power North America provided an example of how these affected-system studies have caused challenges for a proposed 300-megawatt wind project in a part of North Dakota within the territory of grid operator Southwest Power Pool. That project was assigned $3.9 million in costs for transmission upgrades within SPP, some of them more than 350 miles away from the project site.

But it was also assigned costs on the transmission system of the Associated Electric Cooperative in Missouri, as well as on portions of the Midcontinent Independent System Operator’s grid in North Dakota, Minnesota and Iowa, including some nearly 700 miles away. Ultimately,15 upgrades were levied on the project with a total cost of up to $17.6 million, of which only about $3 million worth were located within 280 miles of the project.

That wind farm was only one of 14 different projects from North Dakota to Kansas that were part of a ​“cluster” of projects being reviewed to assess their grid impacts and potential upgrades needed to mitigate them, the report states. If any of those projects dropped out of the interconnection queue — or if any new projects were added within any of the three grid areas involved — that would trigger a reassessment of the combined impacts across all three areas, according to the report.

“We’re paying more than we ever had before, sometimes as much as the cost of our project,” said Adam Stern, Enel Green Power North America’s manager of regulatory affairs and co-author of the report. ​“But it’s the certainty of the cost that we’re focusing on in our reform efforts..”

This isn’t just a problem for energy project developers, Stern said. Grid operators ought to be able to use their interconnection queues to guide their grid-planning process, he said. But Stern added that the independent market monitor for grid operator PJM argued in comments to FERC that ​“it’s difficult or impossible for PJM to include projects in their generation queue in their transmission models because they don’t have certainty that those projects will be completed.” That means that PJM’s grid-planning processes don’t account ​“for projects coming out of that queue — which then exacerbates the problem.”

This opaque and uncertain set of circumstances leads to inefficiencies that ​“translate to costs, and not just on developers,” but on everyone who pays electricity bills, Riley Allen, a commissioner with the Vermont Public Utility Commission, said at this month’s task force meeting with FERC and the National Association of Regulatory Utility Commissioners.

These kinds of complex, interrelated problems don’t lend themselves to easy solutions. As Andrew French, chair of the Kansas public utilities commission, pointed out, many of them are ​“symptoms” of a ​“lack of long-range planning over the past 10 years” and ​“failure to identify the coming demand for these remote, fuel-saving renewable resources and to create the capacity for their interconnection as they were coming along.”

That’s why FERC’s first move in its transmission-reform process was improving long-term grid planning, he said. Still, grid operators are today exploring reforms that could help ease existing interconnection bottlenecks and inefficiencies in the shorter term, French said. Other potential solutions have emerged in comments from stakeholders in FERC’s transmission proceeding.

In the simplest terms, these reforms can be sorted into two main categories: those aimed at reducing the number of speculative projects in interconnection queues and those that seek to make the interconnection-study and upgrade-assessment processes less onerous.

Developer-facing reforms: Putting viable projects ahead of speculative ones

There’s no doubt that the sheer volume of projects seeking interconnection needs to be reduced in order to make the process more workable. Clifford Rechtschaffen, a commissioner at the California Public Utilities Commission, pointed out that state grid operator CAISO is now trying to process a cluster of proposed projects that adds up to 10 times more capacity than the state needs over the coming decade. Other grid regions with competitive energy markets are facing similarly overloaded queues, FERC Commissioner Christie noted.

One key step supported by many state regulators is moving from ​“first-come, first-served” interconnection queues to a process known as ​“first-ready, first-served.” That would require developers to provide more certainty that their projects have some likelihood of actually being built.

Many grid operators already require project developers to put down financial deposits to secure their right to move through successive steps in the interconnection process. Increasing those deposits or moving them into earlier stages of the process could help weed out more speculative projects.

But determining the right set of requirements and hurdles for developers in competitive energy markets is a tricky matter. That’s because those rules need to avoid unfairly disadvantaging one set of developers over another.

“We need to be conscious that we don’t make this a game that only large players can play,” said Ted Thomas, chair of the Arkansas Public Service Commission. That could ​“limit competitive alternatives, and faster, more agile, and perhaps more entrepreneurial market participants.”

Similar issues could arise from ​“fast-tracking” certain projects. Some states may want to provide a smoother interconnection process for projects that are central to their clean energy goals, such as offshore wind projects, Stanek said.

Other projects may seek interconnection at points where big fossil fuel plants are retiring and leaving ample grid-interconnection capacity available, as some offshore wind projects along the East Coast are doing, said Jason Stanek, chair of the Maryland Public Service Commission. ​“It shouldn’t take 1,000 days or four years for [a project] to effectively step into the shoes of an existing generator.”

But FERC Chairman Richard Glick highlighted that any changes in how projects are prioritized may face legal challenges. As the federal agency holding authority over regional transmission organizations and independent system operators, FERC has ​“an obligation under the Federal Power Act to avoid undue discrimination,” he said, referring to the 1920 legislation that created FERC’s predecessor agency. ​“We need to expedite the process, but if we do it by different categories,” such as fast-tracking some projects, we might run into trouble.”

Big clean-energy developers aren’t averse to changing how projects are prioritized in interconnection queues as long as the guidelines are applied fairly, SEIA’s Gizelle Wray said. ​“When we have a higher threshold by which you have to enter the queue — having site control, or a higher money deposit to be in the queue — these are all items that create a better process, and when they’re implemented, they see better outcomes,” she said.

Stern of Enel agreed that implementing ​“readiness milestones” can help reduce crowding of queues. ​“We support this concept because we’d also like to see the queue move faster and have a better idea of how things are going to play out.”

But grid operators also need to do a better job of managing their grid-impact assessments, Stern added. ​“One thing we’re seeing is that we are being asked to provide more and more certainty that our projects will be built, whether it’s higher readiness milestones or more money we have to put down to show we’re ready. But we’re not getting as much certainty as we need in return.”

FERC Commissioner Allison Clements made the same point at this month’s meeting, noting that the utilities that own transmission grids and the regional transmission organizations (RTOs) and independent system operators that oversee interconnection processes for competitive energy markets need to make changes on their end. While she said she’s interested in exploring these developer-facing reforms, that leaves unaddressed ​“whether the transmission providers and transmission owners are meeting their obligations,” she said.

Transmission-facing reforms: Cutting complexity and reducing cost avoidance 

One of the most glaring problems on this front is the lengthy delays in interconnection studies, Clements said. ​“For whatever reasons, RTOs are not able to make their study deadlines,” she said. ​“Are there other ways to ensure that transmission providers and RTOs, when it is in their control, can be better incentivized to meet their deadlines?”

That’s more easily said than done, Clements conceded. One idea is to impose some kind of penalty structure for failure to produce timely grid-impact assessments, she said. But that runs the risk of unfairly punishing grid operators for things beyond their control, such as the pattern of projects being added to and dropping out of queues or the impacts of affected-system studies carried out by transmission entities beyond their borders.

Other options include adding reporting requirements and scorecards to track improvements, Clements said. Hiring more staff or investing in software to get work done more quickly could also help, given the immense workload that many U.S. grid operators face, she said.

But the bigger problem is with the way the interconnection impact studies are conducted, according to Hannes Pfeifenberger, a grid-planning expert and principal with The Brattle Group consultancy. He said there’s much about the intricacies of the studies that could stand to be reformed.

“People like to say that we can solve this by moving the queue around [and] increasing deposits to get people to drop out more quickly,” he said in an interview. ​“But the interconnection criteria are just crazy to start with.”

Enel’s example of a North Dakota wind farm that triggered demands for grid upgrades hundreds of miles away represents an extreme but not unusual case of this excessive complexity, he said. In many cases, it’s highly unlikely that the wind or solar farms being interconnected will ever cause the kinds of grid problems that grid operators are demanding developers pay to fix, Pfeifenberger said.

Another problem with interconnection studies that focus on individual projects is that they can ignore the benefits that upgrades they require could have for everyone else using the grid, he said. He highlighted one such example in a February report for The Brattle Group describing PJM’s approach to measuring the costs of upgrading onshore transmission to support offshore wind being planned at the gigawatt scale off the mid-Atlantic coast.

One PJM study that looked solely at the cost of interconnecting 15.5 gigawatts of offshore wind found the need for $6.4 billion in onshore transmission upgrades, or a cost of $400 per kilowatt of generation capacity, Pfeifenberger said. But a more recent PJM study that combined 17 GW of offshore wind, 14.5 GW of onshore wind, 45.6 GW of solar and 7.2 GW of batteries determined that only $3.2 billion of onshore transmission-grid upgrades would be needed, or about $40 per kilowatt of generation capacity.

The earlier PJM study also found that wind farms off the New Jersey coast would cause significant power flows all the way to the opposite end of PJM’s territory, in Illinois, which would force grid upgrades along the way, Pfeifenberger said. The study ​“didn’t even consider that PJM has market-based congestion management” and operational procedures to address any grid congestion that might occur, he said.

Dan Scripps, chair of the Michigan Public Service Commission, cited affected-system studies as a major complication in trying to enforce a one-size-fits-all planning regime across the country. ​“Costs that come out of these affected-system studies have the potential to kill projects,” he said. But these studies ​“are inherently beyond any one RTO’s ability to control.”

Sometimes these costs can even be imposed after a project has been interconnected and started delivering power to the grid. That’s what happened to a 244-megawatt wind farm built by Tenaska and connected to the Missouri grid operated by Associated Electric Cooperative in 2018. After another project in the queue of neighboring grid operator Southwest Power Pool dropped out, SPP conducted a reassessment that determined that the Tenaska project was now responsible for $99 million in grid upgrades, three times as much as the $33 million that SPP had initially demanded.

FERC Commissioner Clements highlighted the inherent unfairness and inefficiency of interconnection cost-allocation processes like these that ​“land lumpy and large payment obligations on whichever interconnection developer is unlucky enough to be in front of the line…when the system runs out of room.”

In some cases, this structure can lead to accusations of grid operators seeking to extract the cost of necessary grid upgrades from energy projects trying to connect to the grid. In their joint FERC filing, the American Clean Power Association, Advanced Energy Economy and the Solar Energy Industries Association noted that transmission operators are ​“perversely incentivized to identify disproportionate network upgrades in Affected-System studies” and assign their costs to project developers. This allows transmission operators to avoid taking on those upgrade costs and passing them on to their customers — even if those upgrades ​“in many cases are high-voltage ​‘backbone’ facilities” that benefit the system and customers at large.

Since 2003, FERC policy has allowed grid operators to hold project developers responsible for the full costs of grid upgrades needed to connect them. But this ​“participant funding” system, as it’s known, is due for an update in light of the costs that it’s forcing onto project developers, the clean energy groups argue in their joint filing.

Looking for new ways to determine who should pay 

The idea of shifting interconnection-upgrade costs away from project developers didn’t sit well with the state regulators involved in FERC’s transmission joint task force, however. Several commissioners said they opposed any policy change that could risk putting the full costs onto customers served by transmission owners and operators.

Gladys Brown Dutrieuille, a commissioner with the Pennsylvania Public Utility Commission, said that requiring project developers to bear the costs they’ll impose on the grid is an important shield against utility customers being shouldered with increasing costs for what she described as ​“speculative transmission benefits.” In the worst case, sticking utility customers with the bills could lead to ​“stranded transmission costs for generation resources that do not interconnect to the grid,” she noted — a particular concern for upgrades based on the now-excessive number of projects in interconnection queues.

Even when interconnection studies do assign costs for large-scale grid projects to project developers, it’s not clear how to fairly share those costs across the customer base that would end up paying for them in the form of increased rates as a portion of their transmission charges, said French of Kansas’ public utilities commission.

“You may see a wind farm developed in Ford County, near Dodge City, to meet the demand of Amazon or Facebook, to meet corporate sustainability goals,” he said. ​“That’s great — we want to help them meet that demand. But depending on the cost-allocation model…you may have folks in Dodge City paying for upgrades for needs they didn’t necessarily ask for.”

At the same time, ​“for the higher-voltage backbone projects, those do provide larger regional benefits,” French said. ​“To the extent we have studies backing it up that those provide benefits to the region, then I do think we have reason to pursue reform.”

In fact, cost-allocation structures that don’t properly assign these larger benefits run the risk of causing ​“a free-rider problem,” said Scripps of the Michigan Public Service Commission — in essence, one party seeking to push the costs of grid upgrades that it benefits from onto someone else.

To be clear, energy developers aren’t proposing that transmission operators should pay all the costs of interconnection upgrades, FERC Commissioner Clements pointed out. ​“I’ve never had a project sponsor suggest to me they are unwilling to pay their fair share,” she said.

FERC Commissioner Phillips said that structures that push 100 percent of upgrade costs onto project developers could be vulnerable to legal challenge. Previous court decisions have made clear that FERC must design transmission cost-sharing policies that ensure costs are ​“allocated roughly commensurate with benefits.”

This leaves federal and state regulators in the thorny position of needing to craft policies that can get multiple parties to agree to share costs for projects with benefits that can be devilishly hard to quantify. But work is now underway to do just that.

One example is a long-running project aimed at finding ways for the Midcontinent Independent System Operator and Southwest Power Pool to share the costs of grid upgrades that can make room for more renewable energy projects. In March, the grid operators announced the results of that project — a roster of seven transmission projects with a combined cost of about $1.65 billion that’s expected to allow between 28 and 53 gigawatts of projects to be interconnected near the boundary between the two Midwestern grid operators. Here’s a map of the proposed projects.

This represents notable progress in a part of the country where lack of grid capacity and high interconnection-upgrade costs have forced hundreds of megawatts’ worth of clean energy projects to withdraw from queues over the past several years. Even so, Ted Thomas of the Arkansas Public Service Commission noted that ​“the cost allocation with this is extraordinarily difficult.”

“You have to divide your SPP versus MISO benefits, the shared transmission benefits that have to be allocated in both, and then you have the allocation issue related to the developer-funded portion to get somewhere where the benefits exceed the costs,” he said. That latter cost-benefit metric is the all-important measurement that determines whether grid operators can ask utilities within their service territory to share a portion of the costs of building new transmission lines.

Thomas also noted that this approach means building transmission before lining up the projects that will make use of it. ​“How do we know it’s going to be fully subscribed? Who bears the risk of the participant side not showing up?”

Defining boundaries for the grid costs that projects must bear 

In the meantime, for the hundreds of projects already waiting in queues around the country, critics contend that reforms are needed to limit the scope and scale of the grid upgrades that interconnection studies ask them to bear. Matthew Nelson, chair of the Massachusetts Department of Public Utilities, laid out a handful of proposals that have emerged in the FERC transmission proceeding that are intended to do that.

One class of proposals aims to divide costs based on the scale of the voltage of the grid systems involved, he said. In simple terms, interconnecting projects would bear all or most of the costs for upgrading lower-voltage parts of the network but would be responsible for a lower share of the costs of upgrades to higher-voltage, ​“backbone” stretches of the grid.

This isn’t a completely new concept, he noted. In MISO and SPP territory, costs for upgrading parts of the grid at voltages greater than 335 kilovolts are split — 90 percent are paid by interconnecting projects and 10 percent by MISO and SPP utilities and customers.

It’s also similar to the ​“Highway/​Byway” process used to split up transmission costs between local zones and regional zones in SPP territory, said French of the Kansas public utilities commission. This ​“very broad, simple cost-sharing mechanism” assigns lower-voltage upgrades to local zones and higher-voltage upgrades to larger regions. While it’s not designed for interconnection cost-allocation, it could be relatively simple to adapt it to cover the costs of projects based on the zones in which they’re located, he said.

Another concept proposed by Enel Green Power North America calls for splitting up costs based on a measure known as ​“transfer distribution factor,” Nelson said. This is a more complex calculation based on power flow analysis. But in simple terms, it boils down to the idea that generators have their greatest impacts on the portions of the grid closest to where they’re interconnected and the lowest impacts on the parts of the grid farther away. As Nelson put it, ​“if you’re a small generator that’s impacting load, and you’re just impacting a little bit, maybe you shouldn’t pay to completely upgrade a substation.”

Enel’s Stern, who worked out the proposed methodology with Aaron Vander Vorst, Enel’s senior director of transmission, said the concept is to ​“better align network upgrades needed to what’s caused by that specific generator. Anything beyond that — anything that has systemwide benefits — should be addressed in the regional planning process.”

Whatever the method, Nelson said the goal is to ​“have a little more balanced tack between participant funding and some sharing of the costs. How do you align those costs, and how do you align those benefits?”

If only it were easy to answer those questions. 

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