But who is gonna pay for it? Finding balance in grid upgrade cost-sharing
(Who is going to pay for the cost of grid upgrades?)
Northeast states propose models for the future of DER interconnection
“Cost causation should be relegated to the dustbin of history,” says Ed Brolin, vice president of policy development and distributed government relations at RWE.
He’s far from alone in that opinion. But if the customer prompting a grid upgrade isn’t going to pay for it, and the utility won’t either, who will? Several states are experimenting with new cost-sharing mechanisms in an attempt to streamline the interconnection of distributed energy resources, like solar and battery storage.
Last year, Massachusetts established DPU 20-75, a provisional framework for planning and funding upgrades. Several group studies have been filed by Eversource and National Grid, the predominant investor-owned utilities in the region. One has already been approved: DPU 22-47. The rest are expected to be ruled upon in early 2024.
Richard Labrecque is uniquely qualified to discuss this topic. He currently serves as the director of interconnection and utility affairs at Agilitas Energy, a developer of distributed solar and battery storage assets. Unlike many of his peers, Labrecque also spent decades on the other side of the fence as a grid planner at Eversource. Last but not least, I have his email address.
Labreque understands DPU 22-47 as an opportunity for Eversource to “move forward with installing a very expensive set of system upgrades” in order to interconnect a portfolio of distributed energy resources. He adds:
“This new twist is that instead of the DG owners paying for 100% of the cost of the upgrades, the costs are partially funded by retail customers in normal utility rates. The other twist is that the upgrades also ‘unlock’ additional system capacity for additional DG projects. These additional DG projects will be able to interconnect at a known and fixed $/kw cost.”
Richard Labrecque, Agilitas Energy
That fixed cost for additional interconnection is pretty high ($385/KWh +/- 25%), but for developers, some cost certainty is better than none.
In Rhode Island, a customer prompting a system upgrade may be subject to a cost share if the modification is identified to benefit other customers. If a future customer benefits from the upgrade within a decade, they’d be subject to a cost share on a pro-rated basis.
Kathy Castro, director of engineering and asset management at Rhode Island Energy, calls it a “fairly fair” model.
“I haven’t met a developer not happy to get money back,” she laughed. Taxpayers may also favor Rhode Island’s method since the state isn’t fronting costly upgrade expenses.
However, the framework is far from perfect. Its administrative burden is a logistical nightmare, Castro acknowledges, and it can be difficult to evaluate exactly how a single customer may have benefitted from a previous upgrade, let alone the next customer and the one after that. And although developers may get compensation eventually, there are no guarantees, and they still have to pay for the upgrades upfront, extending resources that could be used on other projects.
Getting future legislation right
Castro recognizes developers may not see retroactive cost-sharing as the ultimate solution, but believes Rhode Island is headed in the right direction. She expects future models to include some combination of incentives and integrated grid modernization planning.
RWE’s Brolin agrees. “We should try to figure out all the upgrades that are necessary,” he recommended. “Why aren’t we figuring out what the grid upgrade totally needs to look like and spread that cost across all of society?”
Brolin insists we shouldn’t be worried about how to make utilities whole at this point. Rather, our focus should be on the societal benefits of system upgrades and connecting community solar. He asks utilities to split the bill for modernizing our grid, rather than putting it on the backs of developers.
Labrecque sees value in a model that taxes carbon output and recognizes the larger benefits of grid upgrades. He thinks the traditional approach is too reactive and that a more holistic strategy is required; one that involves planning ahead, preferably with utilities onboard.
“You can’t as a government wave a magic wand and say all interconnection costs will be rate-based because, now, there’s no incentive to find the smart and right connections,” he said. “Utilities will find a way to do it themselves if the right cost-sharing schemes are in place. If they have more skin in the game, they will find a way to do it quicker.”
Philip L. Bartlett II, J.D, chairman of the Maine Public Utilities Commission, was candid about his stance on current legislation at the GridTECH Connect Forum – Northeast event held in Newport, Rhode Island in October.
“I think in all these areas what we’re trying to do is shove new policy direction into (an) old framework. It’s clearly not working,” he stated. Bartlett admits some utility policies have been too restrictive, prohibiting customers from pursuing interconnection altogether.
The chief commercial officer of DSD Renewables, Eric Pollock, says assigning a more predictable cost to interconnect is an important initiative. “It’s something that we have to get right,” he stated. “If there was a better method as to the cost-sharing approach, you certainly would see much more renewables being adopted.”
RWE’s Brolin wants to ensure whatever new schemes we concoct avoid previous pitfalls.
“It’s necessary to critically examine every aspect to determine if it fits in the future,” he warned. “If we don’t change the regulatory paradigm, we will inevitably have a solar market that flourishes for a couple of years but then jams up because cost causation doesn’t work.”
“This is going to cost money and it’s going to have to come from somewhere,” reminded Brolin. “We are trying to transform our society and the cost needs to be borne by electricity bills.”
