According to the IREC, there were 65,000 grid-connected PV installations of all sizes in the U.S. in 2011. In 2012, the number of connections jumped to 95,000, meaning that utilities had to approve 30,000 new interconnection applications over the course of a single year. This figure does not count applications that were considered and rejected.
Residential-type installations are generally put on a ‘fast track’ evaluation process; nevertheless, the sheer volume is a tremendous strain on the small generator interconnection procedures the Federal Energy Regulatory Commission enacted in 2005, when there were a mere 7,000 PV grid connections in the U.S.
‘Most interconnection procedures were designed for a different era,’ says Sky Stanfield, an attorney at Keyes, Fox & Wiedman LLP working on behalf of the IREC to develop a new approach to integrated distribution planning (IDP). ‘The problem is that by 2015, there are projected to be 150,000 grid-connected PV systems.’
According to Stanfield, the current interconnection procedures are largely reactive in that the utility waits for the application to study whether it will be the proverbial straw that breaks the camel's back. For most fast-tracked applications, studies are perfunctory and generally involve checking whether the prospective PV system triggers a review of the circuit's theoretical hosting capacity.
But there is nothing theoretical about the effect the threshold can have on PV installations. In Hawaii, for example, over 20% of distribution circuits are reported as being over the 15% peak load threshold that triggers a hold on applications. This means panels are already on the roofs of residents who are waiting for word on whether they will be allowed to connect their new system to the grid.
Another problem with the grid interconnection application process, Stanfield says, is that the party deemed responsible for exceeding a circuit's capacity has to foot the bill for upgrading the circuit to handle the proposed interconnection. When the applicant is a generating plant or a large commercial or municipal facility, the required upgrade is something that probably would have been factored into the project. When a residential PV installation tips the balance, the homeowner is responsible for the upgrade, which is a non-starter.
Stanfield says the purpose of the IDP proposal the IREC is developing is to get utilities to perform studies to establish the hosting capacity and allowable penetration for all of its circuits. Such planning would also entail forecasting interconnection penetration – PV and otherwise – to enable them to prioritize upgrades to the distribution infrastructure.
Ideally, Stanfield says, circuits that were forecast to exceed interconnection penetration levels could have their hosting capacity upgraded as part of ongoing maintenance instead of having the upgrade triggered by a given interconnection application. Also ideally, the utility would publish the results of its estimated capacity and allowable penetration.
‘The utility could plan and expedite interconnect procedures based on IDP,’ she says.
As we do not live in an ideal world, the issue of cost must be considered. Under the IDP proposal, the utility would bear the costs of the required proactive study. Thus, a state's public utilities commission would have to make rules requiring utilities to do such studies and to publish the results. Furthermore, some mechanism for encouraging – or compelling – utilities to perform circuit upgrades to accommodate anticipated residential PV interconnections will have to be found.
For more information on the IREC's IDP proposal, click here.