Most policies designed to reward small-scale clean energy installations don’t properly account for the values and costs these investments create.
Advocates for distributed energy, like rooftop solar and home batteries, laud the benefits of siting these tools among customers, rather than in the desert far from population centers. Doing so can prevent line losses, outmaneuver congestion in the transmission grid, provide local resiliency and even offset more expensive grid upgrades, depending on where exactly the assets get built.
“Like real estate, it’s all about location, and yet the credits we provide tend to be the same subsidy provided across the entire state or utility territory,” said Jesse Jenkins, coauthor of a new paper on the topic with three other current and former MIT energy researchers.
The federal Investment Tax Credit, a major driver for solar adoption nationwide, applies equally to a rooftop system that helps defer a substation upgrade as to one that doesn’t. Net metering pays the same for exports that deliver to a neighborhood starved by grid congestion as to one that’s already flooded with solar exports. Time-of-use rates add more sophistication by paying more when power is worth more, but they still don’t touch the locational variable.
In fact, besides New York’s Value of Distributed Energy Resources tariff, which is still going through the back and forth of stakeholder comments and revision, it’s hard to find any jurisdiction in the U.S. that is systematically taking DER location seriously.
That’s bad news, because it sets up a misallocation of societal resources, with billions of dollars in incentives on the line, Jenkins and his colleagues argue.
“If sited at the right locations and operated at the right times, DERs can deliver more locational value than more centralized resources,” they write in the latest issue of IEEE Power & Energy Magazine. “However, DERs also tend to cost more on a per-unit basis than their centralized counterparts, which is due to economies of unit scale.”
They suggest that policy should quantify the locational value of an energy asset at a specific place and compare that to the incremental costs of buying that resource at smaller, more expensive scale, rather than at larger scale elsewhere. Optimal policy would steer resources to cases where the locational value outweighs the incremental cost.
Not all solar is the same
States that want to increase their installed solar capacity have some choices to make.
They could focus on the big stuff, with a renewable portfolio standard the compels utilities to procure large amounts of clean energy. They can also create programs to lower the cost of distributed solar, so more households can benefit from local, carbon-free electricity. Many jurisdictions pursue a mix of both.
The major difference is that small residential solar, like home batteries, can easily cost twice as much as utility-scale facilities on a per-kilowatt basis. That hasn’t stopped numerous states from creating programs specifically to advance small-scale clean energy.
Allocating funds to distributed solar can serve other goals, like boosting jobs in that sector and making voters happy. But those metrics fall outside the calculus of optimal energy system planning.
“There’s a real question about whether we’re getting the most net value out of a particular solar system, or could have saved on cost,” Jenkins said.
An opponent of distributed solar would say subsidies for it are a waste of money and call it a day. That’s not what this paper is about: It’s calling for a framework to reward distributed assets for the things they really do better than centralized systems, while acknowledging the places where they don’t really help.
In the long run, this approach serves the goal of grid decarbonization by prioritizing the clean energy projects that deliver the most bang for the buck.
"Decarbonization is a big challenge. We have a long way to go, and we need to be investing our limited capital intelligently," said Scott Burger, lead author of the study.
Name the values
Large power plants take up space and need access to higher-voltage wires to transmit their output. They can’t simply drop into dense urban areas where demand is clustered.
DERs, on the other hand, can move more nimbly, and that generates three major values, as outlined in the study:
- Energy delivery: Assets located close to load can overcome transmission grid constraints. This value rises in areas that are more constrained. They can also minimize resistive losses, which average roughly 7 percent in the U.S. and Europe, the study notes.
- Non-wires alternatives: DERs in the right place can defer or entirely avoid an otherwise expensive grid upgrade, like new wires or a substation. This value depends on where a utility would need to improve the existing infrastructure, either due to age or in response to load growth.
- Reliability: When the macro grid fails, DERs can keep the lights on. The authors note, however, that this typically results in private value for whoever’s home or business maintains power in a blackout. That’s a good reason for those people to pay for those DERs, but not for the public at large to foot the bill, the authors argue.
To illustrate how these values play out in different places, the authors — who also include Samuel Huntington and Ignacio Pérez-Arriaga — describe a case study comparing solar installed in a high-congestion spot on Long Island and an average grid location in Mohawk Valley.
After crunching the numbers for locational transmission value, distribution losses and network investment deferral, the illustrative model shows a clear difference. A 1- to 2-megawatt system delivers $36.8 per megawatt-hour of added value, whereas a 1- to 10-kilowatt system, representing a typical home rooftop installation, incurs $79.3 per megawatt-hour of opportunity cost relative to a 30-megawatt utility-scale project.
Based on the locational accounting at that site, the higher unit cost of the smallest system overruns the quantifiable benefits it provides to the system, so it would be better to invest in larger-scale systems.
At the less-congested, lower-priced Mohawk Valley site, neither the rooftop system nor the 1- to 2-megawatt system added enough locational value to justify their incremental cost. The grid need for them simply wasn’t big enough.
Make it happen
It's hard to argue with the logic that an investment's value should outweigh its incremental cost. There's a strong intellectual case for rate design that incorporates not just time variance but locational variance, and rewards it appropriately. And yet, locational value is in practice hardly anywhere in the U.S.
New York’s Value of Distributed Energy Resources tariff has a head start on this for the U.S., but it’s also a reminder that actually delivering on this concept can be highly technical and complicated, and can’t be finalized overnight.
"There are real technical, regulatory and political barriers there," Burger said of implementing locational value in practice.
On the technical side, going through the math to calculate the locational values is tricky, and it becomes nearly impossible in areas where the distribution systems haven't been digitally mapped and customers lack smart metering.
For regulatory obstacles, locational value flies in the face of the principle of treating all customers equally; the whole point is that some customers should earn more for their DERs than others. That requires customer education, to ensure people know what they're getting into.
The deeper looming question revolves around utility incentives. As long as distribution utilities earn profits through capital investments, they'll have good reason to look for things to build. The promise of DERs is to avoid capital-intensive investments with smaller, cheaper assets that achieve the same function.
Fully internalizing this logic of DERs will likely require a reimagining of utility incentives, like the New York REV principle of awarding profit when utilities save money by deferring a large investment.
As for political challenges, they revolve around the popularity of blanket incentives for distributed solar. The constituencies that like these incentives, including the solar industry itself, gear up when states try to take away net metering.
"Any reform to pricing or subsidies is going to result in a benefit that accrues in the long term," Burger noted. "That reform might have real political consequences now."
Then again, when California replaced pure net-metering with time-of-use rates, the more complex tariff sent a much stronger price signal for solar paired with storage. Installers like Sunrun responded by successfully pushing a higher-value product.
Adopting locational rate design would lower compensation for some solar sites, but could make the higher-value locations much more lucrative. That could be the key to getting industry on board with the concept.
“The whole idea of DERs is that they are able to capitalize on locational value," Jenkins said. "The only way that they can do that effectively is if the rates reflect that."