The birthplace of flight, NASCAR and Michael Jordan is making history once again, this time as one of the leading solar markets in the country. Second, to be exact, in terms of total installed solar capacity. Yes, you read that correctly, North Carolina ranks just behind California on the Top 10 Solar States (2014), and it is now home to more solar capacity (396.6 MW) than all of the southeast states combined, according to the Solar Energy Industries Association. An unexpected but exciting development in the U.S. solar market evolution, considering North Carolina barely registered on the solar radar a few years ago.
So, when North Carolina took up a proceeding over a year ago to revise its interconnection standards, primarily in response to the tremendous solar market growth, it was no surprise to IREC that both utilities and developers came forward eager to address some major challenges relating to how projects are processed and interconnected to the grid. Recent backlogged study queues resulting from a high volume of interconnection requests have prevented renewable energy projects from being developed in a timely manner, which costs everyone more money: utilities, project developers and customers, alike.
After months of meetings, workshops, comments and more comments, the North Carolina Utilities Commission issued on May 15th a long-awaited order adopting revisions to the state’s interconnection standards. And just this week the utilities there filed their compliance tariffs.
As both an active participant in the proceedings, as well as an experienced national expert on interconnection, IREC has focused on North Carolina for quite some time. Ultimately, the commission’s decision is interesting in a number of respects for both how it follows and how it bucks national trends in interconnection best practice development.
When compared to other top solar states, North Carolina has a unique market, with a relatively small number of customer-sited, distributed systems and a sizeable volume of small- to- mid-scale projects. As of October 2014, of the 349 solar projects interconnected in North Carolina, 280 projects, or 80 percent, had capacities of 3 MW or less. The reason for this is the primary procurement vehicle for the majority of the state’s solar capacity is a standard offer contract for Qualified Facilities up to 5 MWs.
As such, the volume of projects seeking to interconnect overwhelmed the traditional process for reviewing each project serially, causing a serious backlog. While the state’s market is unique in some respects, ultimately this issue of a clogged study queue is not. The same challenges arose in California and Massachusetts when the market for distributed generation took off, and more states are starting to face this challenge as growth in small- mid- and large-scale renewable energy continues. What is unique, however, is how North Carolina, as compared with other leading states, has chosen to approach the problem.
North Carolina followed California’s and Massachusetts’ lead on a few important fronts, which will certainly help improve the interconnection process compared to the status quo. First, the new rules adopt more definitive timelines, study deposits and financial security requirements to move projects through efficiently and prevent “queue squatting” behavior that holds system capacity and prevents later projects from moving ahead. Secondly, the new rules consolidate the study process from three to two studies, which saves both developers and utilities time and resources. Thirdly, the adoption of a pre-application report will make it easier for renewable developers to identify optimal locations on the system to avoid costly upgrades (which can, in some cases, kill a project’s economics). As the latter provision goes into effect, the commission may want to consider the value of requiring more sophisticated system mapping tools, like those used in California and other states, to further help identify optimal sites for interconnection.
North Carolina’s recent decision deviates from other leading states in a couple of respects. First, the method for managing the order in which queued projects are studied is different from the group and/or cluster study processes being tried elsewhere. Importantly, North Carolina also chose not to adopt two best practices now used in many leading states and adopted by the Federal Energy Regulatory Commission (FERC) in 2013: 1) Fast Track Eligibility and 2) Supplemental Review.
As the name suggests, group and cluster processes enable utilities to study multiple projects together, which can help minimize the backlog associated with studying each queued project in a serial (one-by-one) manner. North Carolina decided to try a different approach and simply modified the queuing process in an attempt to organize the order in which projects are studied to advance ‘study-ready’ projects ahead of any projects that aren’t moving forward. IREC has not identified a best practice for how to manage the study process in high-volume situations like these, and we look forward to seeing whether the innovations in North Carolina are effective in reducing queue congestion.
Fast Track screening techniques help narrow the number of projects that require a full interconnection study (which can take many months and easily cost upwards of $20,000). Building on the experience of high penetration states like Hawaii, California and Massachusetts, the 2013 FERC SGIP (Small Generator Interconnection Proceedures) “Fast Track” review process increased the size limit for projects connecting on higher voltage distribution lines and located near a substation. It also created a more robust supplemental review process that provides utilities more time to review projects that fail the initial Fast Track screens, recognizing that as the amount of generation on a circuit increases, the risks of system impacts increase, but these risks can sometimes be addressed without the need for a full study.
Given the current and projected volume of projects sized 5 MW or less in North Carolina, it is possible that more well-located projects could pass through an expedited review process, which would help further reduce congestion, save resources, and reduce the incremental costs passed on to customers.
As IREC pointed out in the proceeding, the available data from California and Massachusetts demonstrates that that the Supplemental Review process is having the intended effect of allowing more projects that failed the initial screens to interconnect without undergoing a full interconnection study. For example, in PG&E’s territory in California, of the projects that failed the Fast Track review process, 40 percent of them were able to successfully obtain an interconnection agreement after proceeding to supplemental review. Of the 60 percent of projects that failed supplemental review, very few of them actually decided to go on to the study process. So, instead of wasting time, the supplemental review process actually gave most developers the answer they needed: that interconnection was likely going to be too costly at that location to justify further consideration. And it came within about a month’s time and at a cost of about $2,500, versus requiring a multi-month study process and more than $10,000 in study fees.
The commission, in support of the utilities arguments, asserted that differences in the North Carolina market made the examples from all the other leading states and FERC irrelevant. The utilities sought to lower the size limit for Fast Track projects, and opposed adopting a more robust Supplemental Review process, arguing that larger projects would not likely pass the screens and that the Supplemental Review process would just be a “mini-study” that would ultimately result in the need for most projects to go through the full study process, thereby wasting resources. Unfortunately, the commission did not require the utilities to provide data on the penetration of the circuits or the most commonly failed Fast Track screens, and some of the decisions in the order were made in the absence of solid supporting data to demonstrate that the differences between North Carolina and other states warranted a specialized approach.
While IREC recognizes that each state’s unique circumstances need to be taken into account when evaluating interconnection standards, and that there is not necessarily a one-size fits all approach to interconnection, data and supporting evidence should inform and guide the decision-making process on this highly technical issue. What’s more, forgoing a prime opportunity to adopt proactive best practices and process improvements at a time of unprecedented solar market growth may yield unintended consequences for years or even decades to come. Not only can it result in unnecessary study fees and delayed timelines for interconnection, it may also mean that otherwise cost-effective clean energy projects never get built and their economic and environmental benefits never realized.
As states consider interconnection reform, it is imperative that sound data and evidence remain the decision drivers.. Requiring utilities to collect and report on data about the interconnection process is the best way to ensure that commissions make decisions that are most responsive to the actual conditions on the grid. And, drawing from lessons learned and data available from other states, can prevent the reinvention of wheels and create greater consistency across the country.
IREC appreciates the important steps that the North Carolina Utilities Commission has taken to help address the queue backlogs in the state, and we are hopeful that these changes will help reduce some of the immediate congestion and bring more clean energy projects on-line faster. The commission has also committed to revisiting this issue in two years time. IREC hopes that at that time it will approach the process with more detailed information about current conditions to help inform next steps.
Lead image: Footprint. Credit: Shutterstock.