By Elizabeth Doris

Much progress has been made in the last decade toward standardizing and streamlining interconnection processes. In the United States, the Institute of Electrical and Electronic Engineers (IEEE) publishes standard requirements for various technical aspects of grid interconnection (Keyes & Fox 2008). A number of states and regions have developed standard interconnection procedures to normalize utility-developer interactions (Fink, Porter, & Rogers 2010). In Germany, the legal framework established by the Renewable Energy Sources Act (EEG) has resolved some, but not all, obstacles to connecting PV systems to utility grids (GSIA 2010).

Despite reported progress, interconnection wait times are still considered lengthy by some developers. This article preliminarily compares interconnection processes for small¹⁾ residential applications as well as larger commercial- and utility-scale projects in California and Germany to identify important differences. This work is meant to be a starting point to better understand and inform the different interconnection processes. The article compares the administrative process of establishing interconnection in California and Germany, including the steps taken by developers and utilities and the average length of time utilities take to process applications.

Note that this article is literature-based and is not a primary research endeavor, and thus the information provided herein is limited by the available literature. Primary research could help better inform understanding of the barriers associated with the interconnection of PV systems.

Comparing the Administrative Interconnection Process

It is important to compare the administrative steps involved in establishing interconnection, in order to identify similarities and differences in the Californian and German processes. This section addresses both the steps taken by developers and utilities in order to establish interconnection and the time utilities typically take to process interconnection applications.

Residential-Scale Interconnection in California

The process of applying for interconnection in California varies by jurisdiction and by utility. Most residential PV systems in California serve on-site load and thus are subject to state, rather than Federal Energy Regulatory Commission (FERC), jurisdiction. As such, the procedure for establishing interconnection for residential-scale projects is outlined by the California Public Utilities Commission (CPUC).

California was the second state in the United States to develop interconnection standards, with the establishment of Rule 21 in 2000 (Database of State Incentives for Renewables & Efficiency [DSIRE] 2011; Fink, Porter, & Rogers 2010). The purpose of Rule 21 is to streamline and standardize California’s interconnection procedures (Fink, Porter, & Rogers 2010). In the first 3 years after the establishment of Rule 21, processing time for interconnection requests dropped from approximately 1 year to less than 3 months (Fink, Porter, & Rogers 2010). Under Rule 21, the interconnection process in California can be characterized in four broad steps: 1) application, 2) utility review, 3) interconnection agreement, and 4) installation and commissioning (see diagram in Appendix A).

The first step is to complete an application. Within the process established by Rule 21, applications and requirements vary slightly by utility (DSIRE 2011). Some utilities have moved to streamline and simplify interconnection procedures for small systems. For example, San Diego Gas and Electric (SDG&E) has adopted an online combined net metering and interconnection application for systems 30 kilowatts (kW)²⁾ or less, which is discussed further below.³⁾

During the utility review process, all applicants enter the same screening process, regardless of project capacity (Fink, Porter, & Rogers 2010).⁴⁾ Projects are assessed in an initial review of eight screening criteria. Projects under 11 kW automatically satisfy three of the eight screens (Fink, Porter, & Rogers 2010). Projects that pass the initial review qualify for a simplified interconnection (Fink, Porter, & Rogers 2010).⁵⁾

If systems do not qualify for a simplified interconnection, utilities have an opportunity to perform a review and determine what features and upgrades will be necessary for interconnection (Fink, Porter, & Rogers 2010). Generally, PV systems under 10 kW are granted a simplified interconnection and do not require any supplemental review or interconnection studies (DSIRE 2001).

After completing the utility review process, customers must enter into an interconnection agreement or contract with the utility. For small residential customers, this contract may be combined with the interconnection application.

Finally, the PV system can be installed and commissioned, a process that involves physically connecting to the distribution grid, testing, and authorizing (Cooley, Whitaker, & Prahbu 2003).

Rule 21 sets limits on the time utilities may take to respond to interconnection applications. Utilities are required to notify applicants on the completeness of their application within 10 business days (Fink, Porter, & Rogers 2010). The initial review must be completed by the utility within 20 days (Fink, Porter, & Rogers 2010). Data on residential PV systems processed through the California Solar Initiative provide a case study on utility processing times for interconnection applications (see Table 1). For the time period of July 1, 2010, through September 30, 2010, the average time required for interconnection for each utility, measured from when an application is completed to when a utility grants a PV system owner ‘permission to operate’, was less than 1 month (CPUC 2010). For residential systems, PG&E’s interconnection wait time averaged 16 calendar days, SCE’s averaged 5.9 days, and SDG&E’s averaged just 3.1 days (CPUC 2010). This time estimate only takes into consideration the processing time on the utilities’ end, not the time it takes developers to complete the necessary paperwork, which is addressed in Section 4.1.

Residential-Scale Interconnection in Germany⁶⁾

European Union (EU) law governs Germany’s interconnection process. Under EU law, member states may prioritize the interconnection of renewable energy generators. Germany passed the Renewable Energy Sources Act (EEG) in 2000 (Deutscher Bundgestag 2000) and subsequently updated it in 2004 and 2008. The EEG requires that utilities prioritize connecting renewable energy projects to the grid (Deutscher Bundgestag 2009). However, without a legislated timeframe for responding to interconnection requests, some argue that the law still allows utilities to delay PV projects (GSIA 2010). Further, the exact requirements for establishing interconnection, including technical interconnection criteria, vary by utility (Schmitz & Volkmann 2010).

The interconnection process in Germany follows the same general process as in California, including the application, utility review, and commissioning (see diagram in Appendix B). One noteworthy difference is that in Germany, no interconnection agreement or contract is required of the customer. While contracts are recommended, PV systems may connect to the grid without a contract between the customer and the utility (PV Legal 2011b; Schmitz & Volkmann 2010).

For residential-scale projects, the first step toward interconnection is to submit a grid connection application to the utility (PV Legal 2011c). This usually includes a site map, a circuit diagram, and technical data sheets on the modules and inverter (Schmitz & Volkmann 2010). While the literature refers to this documentation as an application, utilities are required to connect renewables to the grid, barring exceptional circumstances, suggesting that few ‘applications’ are rejected.

In the second step, the utility reviews the application to determine the connection point. The EEG stipulates that for systems of installed capacity up to 30 kWp, located on land already connected to the grid, the existing connection point will be used to connect the new PV system (GSIA 2010). However, it is noted that in some areas with outdated grid infrastructure, particularly rural areas, interconnection studies and grid upgrades are frequently necessary, even for small systems (GSIA 2010). If grid upgrades are required, they are performed and paid for by the utility (PV Legal 2011b).⁷⁾

In a final step, following construction or installation, the PV system is commissioned and connected to the grid (PV Legal 2011a). After receiving the interconnection request and performing the grid study, the utility submits a connection point proposal to the PV system owner (PV Legal 2011c).

According to an industry survey completed by PV Legal, the average time for a utility to complete an interconnection study and submit a connection point proposal for a small, residential project is 4 weeks (see Table 3) (PV Legal 2011b).⁸⁾

Commercial- and Utility-Scale Interconnection in California

This average includes only the utility-end processing time, not the time developers typically need to complete the necessary forms. This issue is discussed in Section 4.2.

Commercial- and utility-scale PV projects may fall under either CPUC or FERC jurisdiction. Those under CPUC jurisdiction must follow Rule 21 interconnection procedures (see diagram in Appendix A). As Rule 21 does not specify any size limits, all applicants are subject to the process described above. Most large projects require supplemental review. Supplemental review may consist of the following: determination of system impact, formal assessment, system study notification and cost estimate, study completion and reporting of results, notification of additional costs for applicant, distribution system modifications, system tests, notification of interconnection approval, and interconnection agreement (Coddington 2011a).

Projects that fall under FERC jurisdiction follow FERC’s Small Generator Interconnection Procedures if they have a nameplate capacity of less than 2 Megawatts (MW) (Fink, Porter, & Rogers 2010). This process is similar to CPUC’s Rule 21. Projects first go through an initial screening process, which consists of a number of technical screens (Fink, Porter, & Rogers 2010). Projects with nameplate capacities between 2 MW and 20 MW, and those that fail the initial screening, must undergo additional studies such as feasibility studies, system impact studies, and facilities studies (Fink, Porter, & Rogers 2010, p 8). Applicants pay for these studies and any necessary transmission upgrades (Fink, Porter, & Rogers 2010). FERC rules prohibit utilities from prioritizing the interconnection of specific generation technologies (Fink, Porter, & Rogers 2010).

The California Solar Initiative provides data on non-residential PV system interconnection times (see Table 2). For the time period of July 1, 2010, through September 30, 2010, the average time required for interconnection for each utility, measured from when an application is completed to when a utility grants a PV system owner ‘permission to operate’, was less than 1 month (CPUC 2010). For non-residential systems, PG&E averaged 13.7 days, SCE averaged 16.1 days, and SDG&E averaged 3.6 days.

Commercial- and Utility-Scale Interconnection in Germany

In Germany, commercial- and utility-scale projects follow essentially the same interconnection procedures as residential-scale projects. PV Legal divides this portion of the market into two groups: commercial and industrial roof mounted systems (up to 50 kWp and ground-mounted systems (up to 5 MWp).

Commercial- and industrial-scale roof-mounted systems (up to 50 kWp) in Germany follow the same process as residential-scale systems to establish interconnection. However, GSIA notes that for these systems, the application for grid connection can be a significant barrier, which sometimes involves long waiting periods and high fees (GSIA 2010). GSIA attributes this to the fact that for systems larger than 30 kWp, there is no legally defined preferred interconnection point, which gives grid operators leeway to obstruct the interconnection process (GSIA 2010). The GSIA report also notes that the difficulty of establishing interconnection for this segment varies a great deal by grid operator (GSIA 2010).

Ground-mounted systems (up to 5 MWp) follow the same process as residential-scale systems, except for two additional steps. Prior to submitting a grid connection application, system operators submit a ‘preliminary request for grid connection’ in order to determine the capacity of the existing infrastructure to support the project (PV Legal 2011e). The GSIA report identifies the application for grid connection for ground-mounted systems as a significant barrier to an expedient interconnection (GSIA 2010). GSIA notes that it is often problematic for system operators and grid operators to come to agreement on the location of the interconnection point and that the process sometimes involves long waiting periods (GSIA 2010). Ground-mounted systems may also need to notify the utility of the completion of construction before continuing with commissioning and connecting to the grid (PV Legal 2011f).

According to PV Legal’s industry survey, the duration of the grid connection process was 7 weeks for roof-mounted commercial and industrial projects and 10 weeks for ground-mounted projects (see Table 3).

Germany and California have similar processes for establishing interconnection for small, residential PV systems. In both cases, systems under a specified installed capacity are exempted from in-depth reviews and studies, though there are some exceptions. Based on this review, utility-end processing time for interconnection requests in Germany and California appear similar. In Germany, utilities take an average of 4 weeks to respond to interconnection requests (by providing connection-point proposals) for residential PV systems 5 kWp or smaller. In California, utilities process California Solar Initiative interconnection applications in approximately 1 to 2 weeks. It appears that in both California and Germany, there is substantial variation in interconnection request processing time, depending on the utility and PV system type (CPUC 2010; PV Legal 2011b).

While superficially similar, the interconnection for large-scale systems in Germany and California differ on a number of important, fundamental points. In Germany, unlike in California, utilities are required to connect any system to the grid and pay for any required studies. Additionally, in Germany, no interconnection agreement is legally required (for any size system), further reducing the obstacles to establishing interconnection. No information is available on utility-end processing of commercial- and utility-scale project interconnection requests in California, so no comparison to Germany can be made by that measure.

Inquiry into a number of key areas would help determine the impact of interconnection policies on overall interconnection time. First, it would be useful to know by how much processing time improves when renewable projects’ applications for interconnection are prioritized over non-renewable projects, as is legislated in Germany. Second, it would be important to study how long the California utilities’ interconnection applications and forms take PV system owners or installers to complete. Similarly, it would be useful to know how owners and installers in both California and Germany perceive the level of difficulty in completing the necessary paperwork. Third, an expanded review, which covers other system types, the procedures and processing time associated with rebate applications, and installation time, would be informative.

Elizabeth Doris has managed clean energy policy analyses for the National Renewable Energy Laboratory (www.nrel.gov) since 2005. She has an MS in Environmental Policy from Johns Hopkins and a BA in Environmental Science from Boston University.

REFERENCES

1) In this article, ‘small’ PV in Germany is defined as systems 5 kWp or less, as this is the cut off used by PV Legal. ‘Small’ PV in California is defined as systems under 10 kW, in accordance with Rule 21.

2) Unless otherwise noted, all references to installed capacity in this paper are stated in terms of DC output.

3) For more information on SDG&E’s process, see http://www.sdge.com/nem/interconnectionRequirements.shtml.

4) Note that while Rule 21 does not expedite residential-scale project applications, in the sense of providing special treatment, the system is designed so that simpler projects exit the process earlier.

5) For more information, see http://www.cpuc.ca.gov/PUC/energy/DistGen/rule21.htm.

6) Documented process information (in English) for the German system is somewhat limited. Most of the information in this report comes from PV Legal, an EU-sponsored research project dedicated to analyzing and reducing bureaucratic barriers to PV deployment. For more information, see http://www.pvlegal.eu.

7) The EEG stipulates that a utility may be exempted from performing upgrades if it can prove that the upgrades are ‘economically unreasonable’.

8) Typical duration is between zero and 10 weeks. Some wait times up to 5 months were reported for small rooftop installations (PV Legal 2011b; German Solar Industry Association 2010, p 15).