California set a standard for defining how distributed energy resources connect to the grid with the passage of Electric Tariff Rule 21 in 2000. At a meeting Thursday, the California Public Utilities Commission finalized an update to that policy that once again puts the state at the forefront of reimagining the grid.
In most markets, murky interconnection standards add considerable costs and time delays to new renewable energy projects that are trying to hook up to the distribution grid. Developers have to pay back the utility for costs incurred while getting the grid ready to receive the new generation, but there's no guarantee the costs will match the utility's estimate. The CPUC's new decision addresses that information gap by establishing greater transparency beforehand about the potential costs associated with interconnection and limiting the cost overruns a developer is liable for. The ruling applies to distributed generation projects that aren't subject to net metering.
"California has made really significant changes to the rules that maintain Rule 21 as the most boldly assertive and effective interconnection standard in the country," said Sky Stanfield, the attorney who represented the Interstate Renewable Energy Coalition in the regulatory proceedings. She added that the outcome is notable for the degree of agreement it enjoys among the key stakeholders, particularly ratepayers, project developers and utilities.
Cost certainty
Before a new generation project goes up, the utility has to assess what changes it needs to make to the existing grid to accommodate the influx of new electricity. If the project doesn't require updates to the existing grid, it will likely get reviewed quickly and cost very little for interconnection. If it would strain the resources of the grid, however, the cost goes up. The utility has to study the effects of the proposal, which can cost around $10,000 or more depending on the complexity of the circumstances. If the project requires upgrading a transformer, that might add $100,000. If it needs distribution line or substation upgrades, the cost could be in the millions.
Under the previous system, the utility provides the developer with a non-binding estimate of the ultimate costs for the project, but the accuracy of that calculation is not guaranteed. If the real-world costs overshoot the projection, the developer still has to pay.
Until now, that is. The CPUC's decision initiates a five-year pilot program that caps a developer's liability to within a 25 percent "cost envelope" of the utility's original estimate. If the interconnection process ends up costing more than 125 percent of the estimate, ratepayers cover the excess for the utility, but only if the utility can establish through an official proceeding that it made a reasonable error in its prediction. This new regime incentivizes greater accuracy from the utility, because if they lowball the estimate unreasonably, they'll be on the hook for the cost overruns. At the same time, it protects developers from debilitating interconnection fees and hedges the exposure of ratepayers through the cost recovery process. It's possible that ratepayers will be affected by this, but only if the utilities consistently make big mistakes in their estimates and convince the CPUC that they were reasonable ones.
More upfront transparency
In a related effort to keep costs down from distributed generation projects, the CPUC called for greater transparency regarding the costs associated with connecting new generation to the grid. The decision orders utilities to produce "a Unit Cost Guide to give generation developers a readily available price list of typical interconnection facilities and equipment...to make cost data available earlier to prospective interconnection applicants."
This sounds pretty dry, but it's hugely important for lowering overall system costs. If developers can see where on the grid they can install new generation without triggering upgrades to substations or distribution lines, they can save time and money for themselves and the utility, ultimately benefiting ratepayers as well.
"By enabling developers to get this information, they can take advantage of areas on the grid where there is capacity," Stanfield said. "That lowers costs for everybody, and it also makes the utility’s job easier."
The ruling also enhances this information sharing by expanding a process known as a preapplication report, by which a developer can request details from the utility on the interconnection requirements of a specific location. This allows developers to file more targeted applications. In states without preapplications, Stanfield said, developers sometimes resort to filing many speculative applications to suss out where the interconnection fees are lowest; that creates a backlog, as utilities have to take time sifting through many applications to get to the serious ones.
The kind of transparency advanced by the new decision offers a potential solution to a broader puzzle for the future of the grid: figuring out the value of distributed energy resources for distribution. Incentivizing new renewables equally in all places can incur unnecessary costs if it requires extensive interconnection upgrades. If utilities give developers the option of informing their plans with a detailed understanding of what the grid can handle and what it can't, they're likely to pursue installations in the locations that allow for quicker and cheaper development. That's an exciting possible outcome, and one other states would do well to watch.