All of us value cost certainty and predictability when it comes to big expenses in our personal and professional lives. We want to know how much something is going to cost overall and upfront, and we want to be able to predict how those costs will be allocated over time. When costs unexpectedly run over budget midway through the process, we start to fret. 

Say you’ve initiated a home renovation based on a set budget and known financing terms. You’ve hired professionals to conduct due diligence on the project to set expectations, you’ve moved out temporarily, paid your permitting and contracting fees, and you’ve been told you’re on track to complete the project on time and within budget. 

Then, halfway through the process, you’re told -- in very uncertain terms -- you could be on the hook for some potentially major additional costs later on. At this point, there’s no information about when or how much you might have to pay. And you hear the costs could be small, but they could just as easily be significant. The only thing that’s clear: You’ll have to pay all of the additional costs before you can live in your house again.

Hardly any type of customer would accept this kind of uncertainty -- such unexpected occurrences are the exception and not the rule.

For the average interconnection customer seeking to connect their distributed energy project to the grid, however, such uncertainty and unpredictability may be a common occurrence.   

Under current laws, interconnection applicants are usually responsible for the costs of connecting their projects to the grid, including any study costs and upgrades needed to accommodate their projects. It’s the “cost-causer pays” principle. Although interconnection rules usually specify application fee amounts -- which generally are meant to cover processing and other administrative costs, and are typically scaled to project size -- an applicant often doesn’t get much other information upfront about what the ultimate, total cost to interconnect might be. 

It’s true that applicants may be able to predict costs or at least ballpark their magnitude at the start of the process, based on project size and location. For example, smaller, rooftop solar projects typically have very low costs. Larger, ground-mounted projects, such as shared solar facilities, typically have higher costs, which increase as project size goes up.

But sometimes smaller rooftop solar projects will trigger upgrades, even major, expensive upgrades. And predicting the types of upgrades prompted by larger projects can be challenging -- especially when there’s no transparency about grid locations and little information about the typical range of costs for those upgrades.

It’s also true that state rules usually require utilities to give applicants estimates of any necessary upgrade costs at some point in the process, and these estimates usually arrive with the interconnection agreement, after the utility has studied the project, and sometimes even earlier in the study process. But few state rules bind utilities to their initial estimates.

As a result, applicants have no formal assurance that the initial estimates will hold, and they can’t confirm what their projects’ final costs will be. This uncertainty is especially challenging for applicants seeking financing. Financiers typically want to know how much a project will cost upfront, and they become much less interested if there’s a potential for those costs to balloon in unpredictable ways.

So how can we make interconnection costs more certain and predictable, and help applicants get access to accurate estimates as early in the process as possible?

There are a few different issues tied up in this question and, as a result, a few different solutions are emerging. 

One important strategy to improve cost predictability, recently adopted in California, is the development of unit cost guides. Published and updated on an annual basis by Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric, these readily available guides offer customers a list of standard prices for typical interconnection facilities and equipment. This information helps customers understand and predict the costs of connecting their projects to the grid well before they initiate the application process. The guides can also help to promote cost consistency across projects. 

State regulators can also improve cost certainty and predictability, and potentially inform unit cost guides, by requiring utilities to track and report the actual costs of system upgrades. For example, in its community solar gardens proceeding, the Minnesota Public Utilities Commission recently ordered Xcel Energy to report all variances between its interconnection cost estimates and the actual costs in its regular community solar garden reports. For variations exceeding plus or minus 20 percent, the commission required Xcel to provide a detailed explanation for the variance.

An equally critical aspect of cost certainty is ensuring that the actual costs for system upgrades fall within a reasonable range of the utilities’ initial estimates. One of the best strategies to achieve this objective is to use some form of an interconnection cost envelope. For example, Massachusetts requires utilities to fix the cost of system upgrades to a specific range early in the process, so applicants aren’t on the hook for unpredictable expenses outside of that range later on. 

Massachusetts specifies that applicants’ costs can’t increase beyond plus or minus 25 percent of the initial estimate provided after the first study phase (impact study) and plus or minus 10 percent of the estimate given after the second study phase (detailed study). If costs ultimately run outside of those ranges, the utilities’ shareholders bear the risk -- but to IREC’s knowledge, that scenario has occurred very rarely, if ever.  

This balanced cost envelope approach reinforces two important principles: customers are responsible for the costs associated with connecting their projects to the grid, and utilities are responsible for developing accurate cost estimates. And the strategy has worked so well in Massachusetts that California recently followed suit, adopting a cost envelope of plus or minus 25 percent. 

As in Massachusetts, if the actual costs of system upgrades in California exceed the 25 percent envelope, utilities will incur those additional costs, and they can either absorb or seek to recover the costs from their rate base. The California Public Utilities Commission clarified that utilities can only recover additional costs from their rate base beyond their original estimate if they can demonstrate a reasonable rationale for their inaccuracy. If the costs are less than 75 percent of the original estimate, the utility’s rate base will retain the difference after a similar showing of reasonableness, to balance the impact on all ratepayers.

Massachusetts has also developed a tool related to the cost envelope -- the Early Interconnection Services Agreement (ISA) -- to help customers ascertain their costs sooner in the process. Early ISAs give applicants the opportunity to lock in cost estimates (plus or minus 25 percent) after utilities complete initial impact studies, rather than waiting for utilities to finish detailed studies that provide later, albeit more accurate, estimates (plus or minus 10 percent).  

Having the option to confirm costs sooner, even if they are not as accurate as possible, is especially useful for applicants seeking project financing in parallel with the interconnection process. 

While cost envelopes are most useful for larger projects that are likely to require system upgrades, there are smart tools to improve cost certainty for smaller projects, too. For example, California imposed a fixed interconnection fee for net-metered projects smaller than 1 megawatt, along with its net metering successor tariff approved earlier this year.

Previously, all interconnection costs were waived for these small projects, but customers are now required to pay a fee of about $100 per application, depending on their utility.  A fixed upfront fee allows California to ensure that all net-metered projects cover the costs of interconnection -- and it eliminates uncertainty and streamlines the process, with no negotiations or delays related to expenses.

Finally, several strategies that may be designed to improve other aspects of the interconnection process can enhance cost certainty and predictability, as well. For example, tools to expand customer access to grid data at the start of the interconnection process, which allow projects to be sited in more optimal locations, keep costs of system upgrades to a minimum. The same can be true of proactive planning, such as Integrated Distribution Planning, which we will be discussing later in this series.    

But being certain about the costs of interconnection is only half the battle when it comes to interconnection. It’s just as important to have a firm understanding of who should pay for what and when. Check back in for our next post, which will contain insights on the topic of cost allocation and how to navigate the concept of sharing interconnection costs among multiple applicants.

***

This is the 5th installment of our interconnection series with IREC. Make sure to read Part 1, Part 2, Part 3 and Part 4.

Erica McConnell is special counsel and Cathy Malina is an environmental law fellow with Shute, Mihaly & Weinberger LLP, attorneys for the Interstate Renewable Energy Council.