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Contract No. DE-AC36-08GO28308

A State-Level Comparison of 

Processes and Timelines for 

Distributed Photovoltaic 

Interconnection in the United 

States

K. Ardani, C. Davidson, R. Margolis, 

and E. Nobler

National Renewable Energy Laboratory

Technical Report

NREL/TP-7A40-63556

January 2015
NREL is a national laboratory of the U.S. Department of Energy

Office of Energy Efficiency & Renewable Energy

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This report is available at no cost from the National Renewable Energy

Laboratory (NREL) at www.nrel.gov/publications.

Contract No. DE-AC36-08GO28308

National Renewable Energy Laboratory

15013 Denver West Parkway

Golden, CO 80401

303-275-3000 • www.nrel.gov

A State-Level Comparison of 

Processes and Timelines for 

Distributed Photovoltaic 

Interconnection in the United 

States

K. Ardani, C. Davidson, R. Margolis, 

and E. Nobler

National Renewable Energy Laboratory

Prepared under Task No. SM13.0532

Technical Report

NREL/TP-7A40-63556

January 2015
NOTICE

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or favoring by the United States government or any agency thereof. The views and opinions of authors 

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Cover Photos: (left to right) photo by Pat Corkery, NREL 16416, photo from SunEdison, NREL 17423, photo by Pat Corkery, NREL 

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iii

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Acknowledgments

The authors would like to thank the following individuals and organizations for their 

contributions to and review of this work: Alison Kling (Con Edison), Ammar Qusaibaty (U.S. 

Department of Energy Solar Energy Technologies Office), Bob Woerner (Pacific Gas and 

Electric), CJ Colavito (Standard Solar), Emerson Reiter (National Renewable Energy Laboratory

[NREL]), Frank Greco (Arizona Public Service), Jacqi Rose Anderson (Hudson Solar), Joseph 

Chavez (NREL), John Teague (New Jersey Board of Public Utilities), Michael Coddington 

(NREL), Michael Conway (Borrego Solar), Miriam Makhyoun (Solar Electric Power 

Association), Sky Stanfield (Keyes, Fox & Wiedman LLP), and Jarett Zuboy (consultant).
iv

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Acronyms and Abbreviations

AHJ Authority having jurisdiction

APS Arizona Public Service

CPUC California Public Utilities Commission

DGIC Distributed Generation Interconnection Collaborative

FERC Federal Energy Regulatory Commission

IOU Investor-owned utility

IREC Interstate Renewable Energy Council

PG&E Pacific Gas & Electric

PTO Permission to operate

PV Photovoltaic

SEPA Solar Electric Power Association

SGIP Small Generators Interconnection Procedures
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Executive Summary

This report presents results from an analysis of distributed photovoltaic (PV) interconnection and 

deployment processes in the United States. Using data from more than 30,000 residential (up to 

10 kilowatts) and small commercial (10–50 kilowatts) PV systems installed from 2012 to 2014, 

we assess the range in project completion timelines nationally (across 87 utilities in 16 states)

and in five states with active solar markets (Arizona, California, New Jersey, New York, and 

Colorado). We evaluate the number of business days required for: 

1. Applying for and receiving utility interconnection review and approval

2. Constructing the PV system

3. Passing a final local jurisdiction building permit inspection and submitting paperwork for 

permission to operate (PTO, the final authorization for system operation) to the utility

4. Receiving PTO from the utility. 

We also assess the portion of projects that required 20 business days (approximately 1 month) or 

more for either the utility interconnection application review and approval or PTO process. The 

threshold of 20 business days may indicate a project or process delay, because interconnection 

timeframe requirements typically mandate that each application and PTO process be completed 

within 15–20 business days (unless that application requires supplemental review or a detailed 

impact study). 

Finally—for California, New Jersey, New York, and Colorado—we compare actual timelines to 

state-level timeframe requirements for utility interconnection application review and approval 

and PTO. All projects sampled meet the system-size eligibility criteria for simplified or fast-track 

review in these states. However, we cannot determine from the data whether a PV system

received utility approval for simplified or fast-track processing, thus precluding an assessment of 

which projects required detailed study. Owing to the large range in data values, we report the 

median number of business days throughout. Our key findings include the following:

• Total Days for Utility Interconnection: Across all system sizes analyzed, the median 

timeline for the full PV interconnection process is 53 days, from the date a PV installer 

submits an interconnection application to the utility to the date the installer receives the 

utility’s PTO. For the residential sample of U.S. projects (up to 10 kilowatts (kW), the 

median number of total days is 52. Generally, larger projects require additional time for 

utility studies and approvals as well as more time for construction. This is reflected in our 

data, which show a median period of 62 total days for small commercial installations 

(10–50 kW). 

• Utility Interconnection Application Review and Approval: Application review and 

approval required the most time of any single process examined in this analysis: a median 

of 18 days for the full sample. Approximately 44% of residential and 50% of small 

commercial projects sampled took 20 days or more. For this subset of installations, the 

median number of days to complete the application process was 38 days for the 
vi

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residential sector and 39 days for the small commercial sector.

1 This indicates that 

projects fall into one of two categories: (a) projects that move through the process well 

below the typical regulated timeframes (10–15 business days), or (b) projects with 

significant delays (i.e., delays were typically 2–3 weeks beyond the requirement).

• PV Construction: For the residential and small commercial samples, the median number 

of PV construction days was 2 and 4, respectively. These numbers are in line with 

reasonable expectations for onsite completion of an installation. Intuitively, longer 

installation times for small commercial systems make sense because installation labor 

requirements generally increase with increasing system size (although not linearly) and 

electrical system complexity.

• Final Building Inspection and PTO Paperwork Submittal to Utility: The median number 

of days to complete the final local jurisdiction building inspection for projects in our 

sample was 4 days. This process includes the physical inspection of the completed PV 

installation for compliance with all building and fire codes in the jurisdiction (typically 1

day or a fraction of 1 day) as well as the time required for the PV installer to schedule 

and arrange the inspection and send all paperwork for final authorization to the utility.

This result indicates that the final building inspection and paperwork submittal process is 

not a major bottleneck for systems up to 50 kW.

• Utility PTO (final authorization for system operation): For the residential sample, the 

median number of PTO days was 10. Median PTO days were slightly higher for small 

commercial projects, at 12 days. Approximately 17% of residential and 25% of small 

commercial projects sampled took 20 days or more. For this subset of installations, the 

median number of days to complete the final authorization process was 28 days for the 

residential sector and 29 days for the small commercial sector.

• State-Level Findings: Our state-by-state analysis indicates that more stringent regulations 

limiting the timeframe for utility application review and approval and PTO may reduce 

project length significantly. The potential impact of more stringent regulations is 

illustrated by New York, where the median process times for these two steps are roughly 

40%–50% below the national level. This same analysis, however, also suggests that such 

regulations do not limit process timeframes for all installations to the targets specified.

Even when limiting the analysis to project sizes eligible for simplified or fast-track 

review, we find that interconnection process delays are common and can range from days 

to several weeks.

 1 Any stated difference between samples (e.g., “the typical process timeframe for residential systems is 

longer/shorter than for small commercial systems”) assumes a significant difference in means (p-value >0.05) based 

on a paired t-test. Test statistics for differences in means can be found in Appendix C.
vii

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Table of Contents

1 Introduction........................................................................................................................................... 1

2 Literature Review.................................................................................................................................. 3

3 Data, Metrics, and Methods................................................................................................................. 4

4 Results................................................................................................................................................... 6

4.1 Total Days for Utility Interconnection .......................................................................................... 6

4.2 Application Review and Approval................................................................................................ 7

4.2.1 Results for Full U.S. Sample............................................................................................ 8

4.2.2 Comparison of Five States ............................................................................................... 9

4.3 Construction ................................................................................................................................ 13

4.3.1 Results for Full U.S. Sample.......................................................................................... 13

4.3.2 Comparison of Five States ............................................................................................. 14

4.4 Final Building Inspection and Paperwork Submittal to Utility ................................................... 14

4.4.1 Results for Full U.S. Sample.......................................................................................... 15

4.4.2 Comparison of Five States ............................................................................................. 15

4.5 Permission to Operate (Final Authorization) .............................................................................. 16

4.5.1 Results for Full U.S. Sample.......................................................................................... 17

4.5.2 Comparison of Five States ............................................................................................. 17

5 Summary Results and Conclusions ................................................................................................. 20

References................................................................................................................................................. 23

Appendix A: Interconnection Process Times for Large Commercial and Industrial Samples ......... 26

Appendix B: Interconnection Process Diagrams for Analyzed States with Timeframe Regulations 

for both Application Review and Approval and PTO (New York, New Jersey, and Colorado)... 27

Appendix C: Statistical Difference in Means between States and Sizes for Different 

Interconnection Processes for the Full Sample of Systems (0–50 kW)........................................ 32
viii

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List of Figures

Figure 1. Process for PV building permitting and utility interconnection .................................................... 1

Figure 2. Timeline analysis metrics based on process for PV building permitting and utility 

interconnection......................................................................................................................... 2

Figure 3. Total days for utility interconnection for five states and full U.S. sample (up to 50 kW)............. 7

Figure 4. Overview of interconnection process used by FERC SGIP and several states, from Coddington 

and Mather (2014).................................................................................................................... 8

Figure 5. Application review and approval days for five states and full U.S. sample (10 kW and under). 11

Figure 6. Application review and approval days for five states and full U.S. sample (10 to 50 kW)......... 12

Figure 7. Construction days for five states and full U.S. sample (up to 50 kW) ........................................ 14

Figure 8. Building inspection days for five states and full U.S. sample (up to 50 kW).............................. 16

Figure 9. PTO days for five states and full U.S. sample (10 kW and under).............................................. 19

Figure 10. PTO days for five states and full U.S. sample (10 to 50 kW) ................................................... 20

Figure 11. Days for each interconnection stage, full U.S. sample (up to 50 kW)....................................... 21

Figure 12. Days for application review and approval and PTO, full U.S. samples of large commercial (50 

to 250 kW) and industrial (250 kW to 2 MW) systems......................................................... 26

List of Tables

Table 1. Total Days for Utility Interconnection for Full U.S. Sample, by Project Size................................ 6

Table 2. Application Review and Approval Days for Full U.S. Sample, by Project Size ............................ 9

Table 3. FERC SGIP Interconnection Timeline Requirements with Freeing the Grid Scoring Criteria.... 10

Table 4. State Timeframe Requirements for Application Review and Approval with Freeing the Grid

Score ...................................................................................................................................... 10

Table 5. PV Projects that Exceeded Application Review and Approval Time Requirement, by State and 

Size......................................................................................................................................... 13

Table 6. Construction Days for Full U.S. Sample, by Project Size ............................................................ 14

Table 7. Building Inspection Days for Full U.S. Sample, by Project Size ................................................. 15

Table 8. PTO Days for Full U.S. Sample, by Project Size ......................................................................... 17

Table 9. State Timeframe Requirements for PTO, by System Size and Interconnection Track................. 18

Table 10. PV Projects that Exceeded PTO Time Requirements, by State and Size ................................... 18
1

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1 Introduction

In the United States, installing a photovoltaic (PV) system and connecting it to the utility grid 

requires multiple approval and process steps spanning the local permitting jurisdiction, installer, 

and utility. Generally, a PV installer must obtain a building and electrical construction permit 

from the local jurisdiction in addition to an interconnection agreement from the utility (Figure 1). 

While the level of coordination between these parallel approval processes varies, local 

jurisdiction building permitting is separate from the utility interconnection process. In this report, 

we focus on the utility interconnection process, PV construction, and final building permitting 

inspection which consists of four distinct steps (Figure 2):

1. Applying for and receiving utility interconnection review and approval

2. Constructing the PV system

3. Passing a final local jurisdiction building permit inspection and submitting paperwork for 

permission to operate (PTO, the final authorization for system operation) to the utility

4. Receiving PTO from the utility. 

We do not examine the timeline for receiving approval for PV construction, which is a stage of 

the local jurisdiction building permitting process that is often applied for concurrently with 

utility interconnection and early in PV project development. Figure 1 depicts this stage in gray.

Figure 1. Process for PV building permitting and utility interconnection
2

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Figure 2. Timeline analysis metrics based on process for PV building permitting and utility 

interconnection

With more than 190 investor-owned utilities (IOUs), 2,000 publically owned utilities, and 870 

cooperatives in the United States (APPA 2014), PV developers encounter wide variation in 

interconnection fees and requirements, which can increase the time and cost of project 

completion. The lack of standardization in building permitting and inspection processes across 

more than 18,000 authorities having jurisdiction (AHJ) can further slow PV deployment. Though 

a growing number2 of states have adopted standard interconnection procedures, these procedures

typically only apply to IOUs

3 and differ among states in terms of fees and requirements, such as 

the use of standard form agreements, capacity limits, specified timelines, insurance requirements, 

and other key considerations (DSIRE 2014).

For interconnection, most state and federal engineering and safety requirements are based on 

IEEE 1547 and UL 1741, but there is no equivalent set of requirements for consistent 

interconnection processes across states and utilities (DSIRE 2014). However, some efforts 

toward implementation of standard process requirements are being made. In May 2005, the 

Federal Energy Regulatory Commission (FERC) enacted the pro forma Small Generator 

Interconnection Procedures (SGIP) to standardize the interconnection process for projects up to 

20 megawatts (MW). The FERC SGIP applies only to facilities subject to FERC jurisdiction, but

it is increasingly being used as a model for state interconnection standards and includes 

provisions for three levels of interconnection4

: (1) a simplified review for certified inverter-based 

 2 As of July 2014, “More than 30 states plus D.C. and Puerto Rico have adopted comprehensive interconnection 

standards that apply to customer-sited systems (both large and small), regardless of whether the system is netmetered” (DSIRE 2014). 

3 In certain states, such as Colorado, interconnection requirements apply to publically owned utilities as well. 

Specifically, Colorado’s interconnection procedures apply to IOUs with 40,000 or more customers, all electrical 

cooperatives, and municipal utilities with 5,000 or more customers. 4 States that have adopted SGIP’s three levels of review include, but are not limited to Colorado, Connecticut, 

Florida, Indiana, Maine, Michigan, Oregon, New Jersey, New Mexico, New York, North Carolina, Ohio, Utah, and 

Virginia (DSIRE 2014).
3

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systems of less than 10 kW, (2) a “Fast Track Process” for eligible generators, and (3) a “Study 

Process” for all other systems of 20 MW or less (FERC 2005). On November 22, 2013, FERC 

issued a final rule that made numerous amendments to SGIP, including expanding fast track 

eligibility5 and adding three technical screens to the supplemental review process. These 

amendments were made, in part, to respond to an increased volume of small generator 

interconnection requests while ensuring the safety and reliability of the electric grid (Coddington 

et al. 2012a).

Meanwhile, the number of distributed PV installations is growing rapidly in the United States,

with approximately 2,000 MW installed in 2013—more than triple the annual capacity installed 

in 2010 (Klemun 2013). Residential and non-residential distributed installations are projected to 

exhibit the strongest growth through 2017 (Klemun 2013), resulting in an ever-increasing 

volume of applications for PV systems to be grid-connected behind the meter. However, longer 

completion times for the distributed-PV interconnection process can increase costs borne by 

local permitting authorities, PV developers, and electric utilities. Thus, a detailed understanding 

of the time required for interconnection and project completion can facilitate planning for the 

anticipated increase in grid-connected, distributed PV systems.

This report examines the timeframes for completing various steps in the PV interconnection 

process. Section 2 reviews the existing literature on interconnection processes and costs. Section 

3 describes our data, metrics, and methods. Section 4 provides detailed results of the analysis.

Section 5 summarizes the results, draws conclusions, and outlines areas for potential future work.

2 Literature Review

To date, research on distributed PV interconnection has largely focused on technical and 

procedural aspects, including potential grid impacts of distributed generation, mitigation 

measures, and model interconnection procedures (CCSE 2013, Coddington et al. 2012a, IREC 

2013a, Coddington et al. 2012b). The Solar Electric Power Association (SEPA) recently 

completed a survey with responses from 64 utilities that identified differences in utility 

interconnection processes. The SEPA study finds that utilities confront common challenges as 

they move toward more streamlined interconnection application processing, including keeping 

customers up-to-date on application status (status transparency), ensuring application accuracy 

and completeness, communicating with customers, and reporting (Makhyoun et al. 2014). In 

addition, Tweedie and Doris (2011) identify key differences between the interconnection 

processes in California and Germany, while the Interstate Renewable Energy Council (IREC)

uses a case study approach to identify areas for improved coordination between the PV processes 

for utility interconnection, local permitting, and incentive applications (IREC 2013b). 

Meanwhile, a small body of work has addressed the cost of interconnection directly (Sena et al.

2014, Navigant Consulting 2013). Finally, the National Renewable Energy Laboratory has 

produced several reports analyzing PV non-hardware balance-of -system (“soft”) costs, including 

the average labor hours required to complete the permitting, inspection, and interconnection 

process (Ardani et al. 2013, Friedman et al. 2013, Ardani et al. 2012).While these studies 

 5 The Fast Track process eligibility criteria for inverter-based facilities was increased from 2 MW to 5 MW, 

assuming the proposed point of interconnection is on a line with voltage between 30 and 69 kV.
4

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identify the interconnection process as a challenging aspect of project development and an 

important area for future research, they do not provide a data-driven, system-level examination 

of interconnection timelines across U.S. states. Our present analysis fills this gap in the literature 

by quantifying interconnection timelines for residential and small commercial PV systems

installed across the United States between 2012 and 2014.

3 Data, Metrics, and Methods

We collected data for more than 30,000 distributed PV systems installed between 2012 and 2014

across 87 utilities in 16 states. The data were primarily sourced from the internal project tracking 

systems of high-volume PV installers. We also collected supplemental data via in-depth 

interviews with members of the Distributed Generation Interconnection Collaborative (DGIC),

6

including nine utilities and 14 PV industry experts (developers and installers, representatives of 

public utilities commissions, and researchers).

To evaluate PV interconnection timelines, we used system-level data that recorded the number of 

business days required to complete the following processes: (a) applying for and receiving utility 

interconnection review and approval, (b) constructing the PV system, (c) passing a final local 

jurisdiction building permit inspection and submitting paperwork for PTO to the utility, and (d) 

receiving PTO from the utility, as well as (e) the complete utility interconnection process from 

start to finish (Figure 2).

These metrics are defined as follows:

(a) Utility Interconnection Application Review and Approval: The number of 

business days from the date a PV installer submits an interconnection application to 

the utility to the date the installer receives interconnection approval and/or a formal 

interconnection agreement, whichever comes sooner.

7 This timeframe combines 

utility reviews for application completeness and compliance with technical 

requirements,

8 each of which have separate state-level timeframe mandates, where 

enacted.

(b) PV Construction: The number of business days from the date a PV installer begins 

construction to the date when construction is complete, including all racking, 

mounting, electrical work, and installation of other balance-of-system components. At 

this stage, the PV system has building approval from the local permitting jurisdiction 

(not examined in this analysis), but it has not yet received the utility’s PTO.

(c) Final Building Permit Inspection and Paperwork Submittal to Utility: The 

number of business days from the date a PV installer completes construction to the 

date the installer submits final paperwork for PTO to the utility. This timeframe 

 6 The DGIC is a stakeholder consortium of more than 100 members focused on identifying replicable innovation for 

the interconnection process. For more information see http://www.nrel.gov/tech_deployment/dgic.html. 7 In some cases, the utility may notify the applicant of interconnection approval prior to issuing a formal 

interconnection agreement. 

8 Depending on the specific utility process, PV system size, and complexity of proposed interconnection, utility 

review for compliance with technical requirements includes initial review screens and then any required 

supplemental review and detailed study.
5

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typically includes the PV installer scheduling any required local jurisdiction building 

inspections, undergoing the inspections, and submitting all final paperwork for the 

utility’s PTO, such as verification of passed AHJ building inspection. This AHJ 

permitting inspection is separate from any utility-required inspections.

(d) Utility PTO: The number of business days from the date a PV installer submits all 

final paperwork to the utility to the date the installer receives final utility 

authorization for system operation. Final paperwork typically includes documentation 

that the completed installation has passed the local jurisdiction building permit 

inspection, but it may also include the interconnection application in utility territories 

that allow the PV installer to submit the application and PTO paperwork together 

following construction and inspection (see Section 4.2 for additional discussion of 

this process).

(e) Total Days for Utility Interconnection: The number of business days from the date 

a PV installer submits an interconnection application to the utility to the date the

installer receives the utility’s PTO. This period was only calculated for systems for

which the installer submitted an application for interconnection separately from the 

final paperwork for PTO. Note that, because there may be additional process steps or 

overlap in the process steps included here, the total days do not necessarily equal the 

sum of the four individual project timeframe components examined in this analysis.

To present results, we segment our full U.S. sample into two PV system-size categories: 

residential (up to 10 kW) and small commercial (10 to 50 kW). Data for system sizes larger than 

50 kW are much more limited, reducing the ability to draw robust conclusions; statistics for these 

larger systems are included in Appendix A. We compare the full U.S. sample to individual 

samples for five states with active solar markets: Arizona, California, New Jersey, New York, 

and Colorado. First, we provide results for the total number of days for the utility interconnection

process. Then we present results for each discrete deployment stage in general sequential order. 

Specifically, we plot the ranges of days required for each stage using box-and-whiskers 

diagrams, where the box represents the interquartile range (between the 25th and 75th percentiles), 

the line within the box represents the median, and the whiskers represent the maximum and 

minimum values, excluding extreme outliers.

For each of the two utility-specific authorizations analyzed in this report, interconnection 

application review and approval and PTO, we assess the portion of projects that required 20 

business days (approximately 1 month) or more. The threshold of 20 business days may indicate 

a project or process delay, because interconnection timeframe requirements typically mandate 

that each application and PTO process be completed within 15–20 business days (unless that 

application requires supplemental review or a detailed impact study). For Arizona, we compare 

the timeframes for utility approvals against the assumed threshold of 20 business days, because 

the state has no timeframe mandates for PV interconnection in place. Then—for California, New 

Jersey, New York, and Colorado—we compare actual timelines to state-level timeframe 

requirements. All projects sampled meet the system-size eligibility criteria for simplified or fasttrack review in these states. However, we cannot conclude from the data whether a system 

received utility authorization for simplified or fast-track processing, thus precluding an 

assessment of which projects required detailed study.
6

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For total days and the stage of final building permit inspection and paperwork submittal to the 

utility, we exclude PV systems for installers who indicated that the timelines for those particular 

systems were altered or extended because of arranging and finalizing financing. Owing to the 

exclusion of these projects and variation in system-level tracking across data providers, the 

amount of data differs by stage in various states. Given the large range in the data, we report 

median values for business days throughout. 

4 Results

The following subsections present results for the total days required for the utility 

interconnection process as well as the time required for each stage in the process. Each shows 

results for our full U.S. sample and our five specific states of interest. Unless otherwise noted, 

any stated difference between samples (e.g. “the typical process timeframe for residential 

systems is longer/shorter than small commercial systems”) assumes a significant difference in 

means with a p-value >0.05 based on a paired t-test. Test statistics for differences in means can 

be found in Appendix C.

4.1 Total Days for Utility Interconnection 

For the residential sample of U.S. projects (up to 10 kW), the median number of total days from 

interconnection application submittal to utility PTO is 52 (Table 1). Generally, larger projects

require additional time for utility studies and approvals as well as more time for construction. 

This is reflected in our data, which show a median period of 62 total days for small commercial

installations (10–50 kW). Across all system sizes, the median is 53 total days.

9 Of the five states 

examined, California projects demonstrate the lowest median number of total days (50), followed 

by Arizona with 54, Colorado with 63, New York with 68, and New Jersey with 90 (Figure 3).

Table 1. Total Days for Utility Interconnection for Full U.S. Sample, by Project Size

System Size Mean Median Std. Dev Sample Size

Residential (up to 10 kW) 60 52 39 7,489

Small Commercial (10–50 kW) 74 62 44 740

Full Sample (up to 50 kW) 63 53 41 8,229

 9 For the full U.S. sample, the contribution of California PV systems is disproportionately large relative to the U.S. 

market. For example, in the first half of 2014, California accounted for 259,136 of the 488,353 total residential PV 

installations completed in the United States (53%) and 12,487 of the 41,803 total commercial PV installations (29%) 

(Greentech Media Research 2014).
7

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Figure 3. Total days for utility interconnection for five states and full U.S. sample (up to 50 kW)

4.2 Application Review and Approval

For states with interconnection application timeframe requirements in place, provisions vary 

across states and by system size. However, in states that follow FERC’s SGIP, utilities must

notify the applicant whether or not the application is complete within 10 business days of 

receiving the application. Then, for complete applications, utilities have an additional 15 

business days to conduct any initial review screens (fast-track screens). If, following initial 

review, the utility determines that supplemental review is required, supplemental review must be 

completed within 20 business days. Lastly, detailed impact studies are to be completed in less 

than 120 calendar days.

Interviewees indicated that detailed studies are most common for PV projects of 1 MW and 

larger; because of the PV size range analyzed in this report (up to 50 kW), it is unlikely that a 

high percentage of projects sampled required detailed study. Interviewees also indicated that PV 

installers often downsize or alter projects to avoid the detailed study process, because its long 

duration and high costs can render a project economically unfeasible. In light of these challenges, 

amendments to the FERC SGIP supplemental review process, which were included in a final rule 

issued in November 2013, were partly intended to decrease the frequency of detailed studies

while ensuring grid safety and reliability. Although significant differences in the interconnection 

application process, practices, and tools exist across utilities, Figure 4 provides a simplified 

overview of the FERC SGIP increasingly being adopted by U.S. states.
8

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Figure 4. Overview of interconnection process used by FERC SGIP and several states, from 

Coddington and Mather (2014)

While utilities commonly prefer that PV installers submit an application for interconnection early 

in project development (i.e., prior to construction), some utilities make an exception for small PV 

projects. For example, in the territories of California’s three largest IOUs,

10 PV installers have a 

utility-designated option of submitting the application for interconnection and PTO paperwork

together, upon completing PV construction and passing all applicable AHJ building inspections. 

In doing so, these utilities essentially combine the application and PTO paperwork into a single, 

final step, thus streamlining the interconnection process for residential and small commercial 

systems that are not likely to cause an adverse grid impact. For example, more than half of the 

projects interconnected under Pacific Gas and Electric’s (PG&E’s) standard net energy metering 

(NEM) program (up to 30 kW) in 2014 did so without any pre-construction utility application 

reviews or approvals. For projects larger than 30 kW, PG&E advises installers to complete an 

interconnection application before construction to identify any potential adverse impacts early on 

and to avoid costly, at-risk construction. For our California sample, 30% of residential and 39% 

of small commercial projects completed separate interconnection application and PTO 

paperwork, compared to more than 90% of all projects sampled in Colorado, New York, and 

New Jersey.

However, as grid-connected PV capacity grows, submitting applications earlier in the PV 

development process may become increasingly necessary even for smaller systems, to identify 

grid impacts resulting from higher interconnection volumes. This has been an issue in Hawaii, 

where PV has grown rapidly. Tension between residential PV installers and utilities has arisen 

when installers have built PV systems before utility application reviews, only to learn that the

utility will require a detailed impact study, costing up to $25,000, prior to issuing PTO.

11

4.2.1 Results for Full U.S. Sample

Application review and approval requires the most time of any stage analyzed in this report. The 

medians are 18 days for residential and 17 days for small commercial installations, but this 

difference is not statistically significant (Table 2). Across all system sizes, the median is 18 days.

 10 San Diego Gas and Electric, Pacific Gas and Electric, and Southern California Edison. 11 From personal communication with interviewees.
9

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Approximately 44% of residential and 50% of small commercial projects sampled took 20 days 

or more; for this subset of installations, the median time to complete the application process was

38 days for the residential sector and 39 days for the small commercial sector. While the cause of 

longer application approval timeframes cannot be identified from the data, they could be 

attributed to PV installers submitting incomplete or incorrect applications that required rework 

and resubmittal, lengthy utility reviews due to application backlog or internal processes, utilityrequired supplemental reviews or impact studies beyond initial screens, or a combination of all 

three. While further investigation into the cause of application approval delays is needed to 

inform the implementation of time-saving measures, potential solutions include clarifying and 

simplifying application requirements, using standard interconnection forms and paperwork 

across utilities, and streamlining the utility review process with electronic and automated 

tracking.

Table 2. Application Review and Approval Days for Full U.S. Sample, by Project Size

System Size Mean Median Std. Dev Sample Size

Residential (up to 10 kW) 27 18 33 12,462

Small Commercial (10 – 50 kW) 28 17 36 1,198

Full Sample (up to 50 kW) 27 18 33 13,660

4.2.2 Comparison of Five States

In comparing actual timelines for application review and approval to state timeframe 

requirements in California, Colorado, New Jersey, and New York, we consider the timeframe 

requirements for utility application completeness review and initial screening in each state. We 

do not include additional time allowances for supplemental review and detailed study, because 

these are highly project dependent. In addition, from our data, we cannot account for the 

numerous permutations of project-specific exceptions, utility-applicant interactions, and 

paperwork exchanges typical of review and study processes beyond initial screening. However, 

all projects sampled meet the system-size eligibility criteria for simplified or fast-track review in 

these states. 

For each state, we consider the unique system-size criteria for interconnection and corresponding 

timeframe requirements. For example, under California’s Rule 21, all projects up to 2 MW in 

size are eligible for fast-track processing.

12 In contrast, for systems up to 2 MW, Colorado and 

New Jersey both allow for two tracks based on system size and complexity: Level 1 for systems 

up to 10 kW and Level 2 for systems up to 2 MW (New Jersey Office of Administrative Law

2014). New York also has two procedures, but with different size thresholds: an expedited 

process for systems up to 50 kW and a separate process for systems up to 2 MW. For Arizona, 

we compare application review and approval timeframes to an ideal threshold of 20 business 

days (approximately 1 month), because there are no state-level requirements in place.

Interconnection process flow diagrams are included in Appendix B for states with timeframe 

 12 Structured after FERC’s SGIP, state-level fast-track procedures typically apply to systems up to 2 MW. In a final 

rule issued on November 22, 2013, the system-size eligibility for SGIP’s fast track application process was raised 

from 2 MW to 5 MW. As of October 1, 2014, the key states examined still had size thresholds of 2 MW in place.
10

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

regulations for both application review and approval and PTO (New York, New Jersey, and 

Colorado).

IREC and Vote Solar’s annual Freeing the Grid report examines the differences in 

interconnection standards across states and awards each state a score based on the degree of 

consistency with FERC’s SGIP (IREC 2013c). Table 3 shows the FERC SGIP interconnection 

timeline requirements and the corresponding Freeing the Grid scoring criteria. Table 4 shows the 

state-level application timeframe requirements and total interconnection timeline score for each 

of the states analyzed, except Arizona. The total maximum interconnection timeline score 

possible is 5. However, the highest score awarded to any state in 2013 was 4.

Table 3. FERC SGIP Interconnection Timeline Requirements with Freeing the Grid Scoring Criteria

Points 

Possible

FERC SGIP Interconnection Timeline Requirements

+1 Application completeness reviewed in up to 10 business days

+1 Initial review screens, if any, applied in up to 15 business days

+1 Supplemental review, if any, applied in up to 20 business days

+1 Timeframe for utility completion of study process is less than 120 calendar days

+1 Timeframe specified for utility to provide interconnection agreement

Table 4. State Timeframe Requirements for Application Review and Approval with Freeing the Grid

Score

State Freeing the Grid

Timeframe 

Requirement 

Score (out of 5)

System Size 

Eligibility

Days for 

Completeness 

Review

Days for 

Application 

Review (initial 

screens)

Total Days for 

Application 

Review and 

Approval

CA 4 up to 2 MW 10 15 25

NY 3 up to 50 kW 5 10 15

up to 2 MW 5 15 20

NJ 3 up to 10 kW 3 10 13

up to 2 MW 3 15 18

CO 4 up to 10 kW 10 15 25

up to 2 MW 10 15 3013

AZ N/A. As of the writing of this report, Arizona has no standard timeframe requirements in place.

 13 In Colorado, for systems of 10 kW to 2 MW, 30 days includes an extra 5 days for interconnection agreement 

execution (CCR 2014), though it is not uncommon for utilities to notify the applicant that the proposed generation 

has been approved in advance of an interconnection agreement being issued. In addition, 30 days assumes no 

supplemental review required. If required, the total days prescribed for application review and approval doubles to 

60. 
11

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Of the five individual states examined, New York demonstrates the lowest median number of 

days for PV system application review and approval (10 days for residential and small 

commercial), followed by New Jersey (14 days for residential, 15 for small commercial), 

California (20 for residential, 23 for small commercial), Arizona (22 for residential and small 

commercial), and Colorado (32 for residential, 25 for small commercial) (Figures 5 and 6). The 

22-day difference between a typical (median) residential project in New York and Colorado may 

indicate the effectiveness of state-level regulations; for systems up to 2 MW, New York utilities 

are required to complete application review and approval in 10 fewer days than are Colorado 

utilities14 (see Table 4). However, many projects in both states exceed the prescribed timeframes, 

as shown in Figure 5 (for residential) and Figure 6 (for small commercial) where the state 

timeframe requirements are represented as red lines. 

Figure 5. Application review and approval days for five states and full U.S. sample (10 kW and 

under)

 14 In New York, regulated utilities are allowed 15 business days for application review and approval for systems up 

to 50 kW, and they are allowed 20 days for systems of 50 kW to 2 MW (New York Standard Interconnection 

Requirements (SIR)). In Colorado, utilities are allowed 25 business days for systems up to 10 kW, and they are 

allowed 30 days for systems of 10 kW to 2 MW (CCR 2014).
12

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Figure 6. Application review and approval days for five states and full U.S. sample (10 to 50 kW)

Table 5 provides additional detail, giving the total time requirement for utility application 

completeness review and initial screens (“Time Req.”), the percentage of applications that 

exceeded the time requirement, and the median application review and approval time for those 

projects that exceeded the requirement. In Colorado, 58% of residential and 45% of small 

commercial projects sampled exceeded the mandated timeframes of 25 days and 30 days, 

respectively. For this subset of installations, the median time to complete the application process 

was 50 days for the residential sector and 59 days for the small commercial sector. In New York,

38% of all projects sampled exceeded the prescribed timeframe of 15 days, and the median time

to complete the application review and approval process for these projects was 49 days for 

residential and 60 days for small commercial. With the exception of California and Arizona, for 

projects that exceeded regulated timeframes, there are longer delays for small commercial 

projects compared to residential; a typical small commercial project was delayed by an 

additional 9–11 business days. 
13

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Table 5. PV Projects that Exceeded Application Review and Approval Time Requirement, by State 

and Size

Residential (up to 10 kW) Small Commercial (10–50 kW)

State Time Req.

(business 

days)

Applications

Exceeding Time

Req. (%)

Median for 

Applications

that Exceeded 

Time Req. 

(business days)

Time Req.

(business 

days)

Applications

Exceeding Time

Req. (%)

Median for 

Applications

that Exceeded 

Time Req. 

(business days)

CA 25 37% 38 25 47% 39

NY 15 38% 49 15 38% 60

NJ 13 52% 18 18 42% 27

CO 25 58% 50 30 45% 59

AZ [20]* 53% 43 [20]* 54% 43

* 20-day threshold is assumed for analytic purposes, because Arizona has no interconnection timeframe 

requirements.

With respect to enforcement mechanisms for utility compliance with interconnection timeframe

requirements, penalties and procedures vary across states. For example, in California, IOUs are 

required to submit quarterly reports of “delayed” systems to the California Public Utilities 

Commission (CPUC). Then, depending on the circumstances, the CPUC can levy penalties and 

mandate behavioral and process changes. Meanwhile, Massachusetts has taken one of the most 

comprehensive approaches to date. On July 31, 2014, the Massachusetts Department of Public 

Utilities issued Order DPU 11-75-F, approving a "Utility Timeline Enforcement Mechanism."

Under this mechanism, utilities face a maximum penalty for noncompliance of twice the amount 

of interconnection fees collected in a year, up to a certain cap that is utility specific. The order 

also allows for a 5% dead band, with no penalties imposed for average processing times up to 

105% of the regulated timeline, then a fixed 0.1% penalty by utility up to the maximum of 115%

of the regulated timeline (DPU 2014).

4.3 Construction

Distributed PV system construction consists of positioning and attaching racking and mounting 

materials, installing and stringing modules, running conduit, and installing the inverter (unless 

the system has alternating-current modules with integral inverters). Average timeframes and cost 

for PV system construction have decreased in the United States due to the advent of streamlined

balance-of-system components and the maturation of the solar industry workforce. 

4.3.1 Results for Full U.S. Sample

For smaller residential systems (10 kW and under), installation can be completed in as little as 

one day (Morris et al. 2013), though construction time requirements increase with increasing 

system size (Goodrich et al. 2012). In our sample, the median number of construction days is 2 

for residential systems and 4 for small commercial systems (Table 6). Across all system sizes, 

the median is 2 days. 
14

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Table 6. Construction Days for Full U.S. Sample, by Project Size

System Size Mean Median Std. Dev Sample Size

Residential (up to 10 kW) 4 2 8 24,401

Small Commercial (10–50 kW) 7 4 15 2,351

Full Sample (up to 50 kW) 4 2 9 26,752

4.3.2 Comparison of Five States

Figure 7 shows system construction days for our five states and the full U.S. sample. Variation in 

mean construction timeframes across the states examined is largely not statistically significant, 

with the exception of the differences between Arizona and California and between California and 

New York. These results may overestimate construction timeframes in terms of actual labor 

hours worked, because the level of data granularity captures the complete business cycle 

timeframe, from the date construction started to the date construction was completed. Half days 

worked and exact labor hours for construction are not captured.

Figure 7. Construction days for five states and full U.S. sample (up to 50 kW)15

4.4 Final Building Inspection and Paperwork Submittal to Utility

For a PV installer to receive final interconnection authorization from the utility, it must first 

submit verification of passing final building inspection, which is often completed by the city,

county, state, or city and county. In addition, for net-metered systems, it is common for the 

utility to require the AHJ to issue a meter clearance via letter, email, or fax before the utility will 

install and enable the meter. Building inspections are separate from any utility-required 

inspections or witness testing, and most AHJs require at least one inspection of the completed 

PV system before the permit is finalized. However, the exact number of building inspections can 

 15 For the full U.S. sample, the median and 25th percentile both have values of 2 because of the relatively small 

spread in observations.
15

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

vary, with some AHJs preferring two inspections: a rough inspection prior to construction and a

final inspection following construction. Also, in some jurisdictions, PV installers are required to 

complete separate building (structural), electrical, and fire inspections. It is important for the 

completed PV system to adhere to the original plans submitted to the local permitting authority, 

because alterations may require PV system changes and additional inspections.

For the purposes of this analysis, building inspection timeframes are from the date construction 

is completed to the date the PV installer submits all final paperwork for PTO to the utility, 

including verification of passed AHJ inspection. Thus, building inspection timeframes are for 

final inspection of fully installed PV systems and include the business days required to schedule 

the inspection, complete the inspection, and compile and send all the final documentation

required for PTO to the utility. In some jurisdictions, the AHJ sends verification of passed 

building inspection directly to the utility, thereby eliminating the need for the installer to do so.

Typically, for approved systems, the actual final building inspection is completed in a single day, 

but the business days required for the full process from scheduling the inspection to finalizing

and sending the proof of passed inspection to the utility varies. For example, inspection-related 

delays could occur when a customer or installer is not present for the final inspection and it must 

be rescheduled. This is common in states with a high percentage of seasonal residents, like 

Arizona, where it can be more difficult to coordinate inspection times with the homeowner, 

installer, and AHJ. 

4.4.1 Results for Full U.S. Sample

While the median inspection timeframe for both residential and small commercial systems is 4 

business days, on average, inspection takes longer for small commercial systems (Table 7).

Table 7. Building Inspection Days for Full U.S. Sample, by Project Size

System Size Mean Median Std. 

Dev

Sample Size

Residential (up to 10 kW) 6 4 8 7,925

Small Commercial (10–50 kW) 7 4 8 575

Full Sample (up to 50 kW) 6 4 8 8,500

4.4.2 Comparison of Five States

Of the five individual states examined, for the full sample (up to 50kW) California has the lowest 

median number of days for inspection (3), followed by Arizona with 7, Colorado with 9, and 

New York and New Jersey with 10 (Figure 8). The results for New York are less robust because

of the smaller number of observations there compared to the other states examined.16

 16 When comparing New York against the other samples, the difference in inspection days is only statistically 

significant between New York and California and between New York and the full U.S. sample.
16

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Figure 8. Building inspection days for five states and full U.S. sample (up to 50 kW)

4.5 Permission to Operate (Final Authorization)

Once PV construction and final AHJ building permit inspections are completed, the installer 

submits all paperwork required for PTO to the utility. This paperwork includes verification of 

passed building inspection, but it may also include the interconnection application in utility 

territories that allow the PV installer to submit the application and PTO paperwork together, 

following construction and AHJ building permit inspection (see Section 4.2). Upon review and 

approval of all the paperwork required for final authorization, the utility is likely to install a net 

meter (for net-metered systems) and issue a PTO letter. Only upon receipt of the PTO letter is the 

installer authorized to energize the system. Many state-level requirements mandate specific 

timeframes for the utility to issue PTO once all required paperwork is received. These timeframe

requirements vary by system size and interconnection complexity, but they typically range from 

5 to 10 days for residential and small commercial systems and as high as 40 days, or longer, for 

large commercial systems or projects requiring additional witness testing by the utility.

While this analysis does not examine the timeline for utility-required inspections, these 

inspections can extend the total time for PV interconnection. Certain utilities, such as Arizona 

Public Service (APS), have streamlined the final authorization process by waiving any pre-PTO 

inspections for residential PV installations. Specifically, APS allows PV installers to “selfcertify” eligible residential projects, thereby acknowledging that all applicable AHJ permitting

and utility interconnection requirements have been met.17 Enactment by APS of self-certification 

for residential PV was largely in response to a rapid increase in interconnection applications, 

from 325 residential applications received in 2006 to 9,000 received in 2013 (APS 2014). As a 

result, only about 10% of residential PV projects installed in APS territory in 2013 required any 

pre-PTO inspections.

 17 Project eligibility for self-certification in APS territory includes residential PV with up to three inverters, no 

battery storage, and typically up to 12 kW.
17

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

4.5.1 Results for Full U.S. Sample

The median number of days for PTO among the projects sampled is 10 for residential systems

and 12 for small commercial systems (Table 8). Across all system sizes, the median is 10 days. 

Approximately 17% of residential and 25% of small commercial projects sampled took 20 days 

or more. For this subset of installations, the median time to complete the final authorization 

process was 28 days for the residential sector and 29 days for the small commercial sector.

We find no material difference when comparing PTO timelines for projects in which the 

interconnection application and PTO paperwork were submitted separately per the typical 

interconnection process, versus those in which the application and PTO paperwork were 

submitted together following construction and AHJ inspection. This indicates that submittal of 

the application in conjunction with PTO paperwork, as permitted by the three main California 

IOUs (see Section 4.2), does not slow the PTO process.

18

Table 8. PTO Days for Full U.S. Sample, by Project Size

System Size Mean Median Std. Dev Sample Size

Residential (up to 10 kW) 13 10 13 31,685

Small Commercial (10–50 kW) 16 12 16 2,740

Full Sample (up to 50 kW) 14 10 14 34,425

4.5.2 Comparison of Five States

Here we compare actual timelines to state-level requirements for PTO in Colorado, New Jersey, 

and New York. Similar to application review and approval, all projects sampled meet the systemsize eligibility criteria for simplified or fast-track review in these states. For Arizona, a state with 

no PTO timeframe requirements, we use a comparative limit of 20 days to assess PTO delays.

Like Arizona, California does not have a specific PTO timeline requirement. However,

California does have a statutory requirement (Public Utilities Code sections 2827 and 2827.8)

that, for all net-metered PV systems (up to 30 kW), the utility must issue PTO within 30 days of 

receipt of a complete interconnection application (Legislative Counsel of California 2014).

19 On 

account of the data collected, we evaluate the portion of projects in California that took longer 

than 30 days to receive PTO from the date the application was approved. This approach likely 

underestimates the portion of projects that exceeded the 30-day requirement, because it does not 

account for the period from when a complete application was received to when it was approved. 

Generally, regulations for PTO timeframes are flexible to allow for additional utility witness 

testing and inspection prior to authorizing an installer to energize a completed PV system. For

example, New Jersey utilities must issue a PTO letter within 5 days if utility inspection is 

waived, but they are allowed up to 20 days if witness testing and/or additional inspections are

 18 The mean PTO time for projects in which the application and PTO paperwork were submitted together is 13.8 

business days, compared to 14.2 business days for projects in which the application and PTO paperwork were 

submitted separately. The difference in means is statistically significant (p-value = 0.03), but it is not materially 

different owing to rounding. For both project types, the median PTO time is 10 business days. 19 Faster application processing and approval timeframes have been attributed to this legislated mandate (according 

to a personal communication with an interviewee).
18

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

required for systems up to 10 kW. These timeframes increase by 5 days for systems up to 2 MW.

Colorado has the same regulations for all systems up to 2 MW: 5 days if utility inspection is 

waived and 10 days if witness testing and/or additional inspections are required. Table 9

compares state-level requirements for PTO, by system size and interconnection track.

Table 9. State Timeframe Requirements for PTO, by System Size and Interconnection Track

State System-Size 

Eligibility

Days for PTO (if 

inspection, witness test 

waived)

Days for PTO (if inspection, 

witness test NOT waived)

CA All net-metered PV systems must receive PTO within 30 days of receipt of a 

complete application.

NY up to 50 kW 5 5

up to 2 MW 10 40

NJ up to 10 kW 5 20

up to 2 MW 10 25

CO up to 10 kW 5 10

up to 2 MW 5 10

AZ N/A. As of the writing of this report, Arizona has no standard timeframe

requirements in place.

For the purposes of assessing the portion of projects that exceeded regulated PTO timeframes, 

we use the higher of the two cut-offs to account for any potential, but allowed, final utility 

inspections (Table 10). Table 10 lists for all five states the time requirement for utility PTO 

(“Time Req.”), the percentage of projects that exceeded the time requirement, and the median 

PTO time for those projects that exceeded the requirement.

Table 10. PV Projects that Exceeded PTO Time Requirements, by State and Size

Residential (up to 10 kW) Small Commercial (10–50 kW)

State Time Req.

(business 

days)

Applications

Exceeding 

Time Req. 

(%)

Median for 

Applications

that Exceeded Time

Req. (business days)

Time Req.

(business 

days)

Applications

Exceeding 

Time Req. (%)

Median for 

Applications

that Exceeded 

Time Req. 

(business days)

CA [30]* 38% 44 [30]* 49% 50

NY 5 53% 11 5 58% 11

NJ 20** 23% 28 25** 9% 29

CO 10** 10% 38 10** 51% 19

AZ [20]*** 22% 28 [20]*** 24% 28

* While California does not have a specific PTO timeline requirement, it has a statutory requirement that all net-metered 

PV systems (up to 30 kW) be issued PTO within 30 days of application.

** We use the requirement upper limit for projects, which assumes the utility inspection and/or witness test are not waived.

*** A 20-day threshold is assumed for analytic purposes, because Arizona has no interconnection timeframe requirements.
19

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Figure 9 and Figure 10 graphically depict the differences between actual PTO days and state 

time requirements (red lines, for Colorado, New York, and New Jersey). As shown in these 

figures, New York has the lowest median number of days for PTO (6 for residential and small 

commercial) among the five states examined, just as it had the shortest application review and 

approval timeline (Figure 5 and Figure 6). It is followed by Colorado (10 days for residential, 11 

for small commercial), California (10 for residential, 12 for small commercial), New Jersey (11

for residential and small commercial),20 and Arizona (12 for residential, 13 for small 

commercial). Compared to Arizona, a state with no timeframe requirements for PTO, median 

completion times in New York are faster. However, the differences in PTO time frames between 

Arizona and the other two states with PTO regulations (Colorado and New Jersey) are minimal

and not statistically significant.

21 This indicates that, while the adoption of state-level timeframe

requirements may lead to overall lower median processing times, other factors must be 

considered when identifying causes of variation between states. These factors could include 

differences in utility processing platforms and tools, witness-testing requirements, and utility

customer-satisfaction goal setting and tracking. 

Figure 9. PTO days for five states and full U.S. sample (10 kW and under)

 20 New Jersey’s median PTO timelines for residential and small commercial systems are not statistically different 

than any other state’s timelines, with the exception of New York’s.

21 Includes residential and small commercial samples.
20

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Figure 10. PTO days for five states and full U.S. sample (10 to 50 kW)

Furthermore, most systems are smaller than 10 kW in all states. Thus, the lower median 

completion time in New York suggests that the lack of a specialized interconnection track for 

projects 10 kW and under is not a notable source of PTO delay for residential projects, relative to 

the other states examined. However, even in New York many eligible systems do not receive 

PTO approval within the timeframe requirement of 5 days. Specifically, 53% of residential and 

58% of small commercial projects sampled in New York exceeded the mandated PTO 

timeframe. For these installations, the median time required to complete the PTO process was 11

days for both the residential and small commercial sectors.

5 Summary Results and Conclusions

Our analysis quantifies the substantial time required for distributed PV interconnection processes

and deployment in the United States. Based on our national sample across 87 utilities in 16 

states, the median total project length for distributed PV systems installed between 2012 and 

2014 was 53 business days (40–70 days between the 25th and 75th percentiles). Figure 11 shows 

the range in values across our full U.S. samples for the specific project timeframes analyzed. Of 

these, application review and approval was the most time consuming, requiring a median of 18 

days (about 3.5 weeks), followed by PTO, requiring a median of 10 days (2 weeks). System 

construction and building inspection required significantly less time, with median timeframes of 

2 and 4 days, respectively.
21

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Figure 11. Days for each interconnection stage, full U.S. sample (up to 50 kW)

We also compared results by system size, analyzing residential (up to 10 kW) and small 

commercial (10–50 kW) systems. As expected, larger systems generally required more total 

process and project completion time (Table 1). Across our full U.S. sample, the median time 

required for construction was 2 days for residential systems and 4 days for small commercial 

systems. The mean inspection time is slightly longer for small commercial systems than for 

residential systems, though both have a median of 4 days. Application review and approval 

timelines do not differ statistically for residential and small commercial systems. Approximately 

44% of residential and 50% of small commercial projects sampled took 20 days or more. For 

these installations, completing the application process took a median of 38 days for the 

residential sector and 39 days for the small commercial sector. This indicates that projects fall 

into one of two categories: (a) projects that move through the process well below the typical 

regulated timeframes (15–20 business days), or (b) projects with very significant delays (i.e., 2–3 

weeks beyond the typical regulated timeframe). Obtaining PTO required a median of 10 days for 

residential systems and 12 days for small commercial systems. Approximately 17% of residential 

and 25% of small commercial projects sampled took 20 days or more. For these installations, 

completing the final authorization process took a median of 28 days for the residential sector and 

29 days for the small commercial sector.

Finally, we examined project completion timeframes in five key PV states: Arizona, California, 

Colorado, New Jersey, and New York. Our results suggest considerable variation in time 

requirements among states. By creating uncertainty, such variation can make installers’ 

workflow planning more difficult and generally reduce the efficiency of their business processes. 

Our state-by-state analysis does suggest that more stringent regulations limiting the timeframe 

for application approval and PTO might reduce project length, as in New York. This same 

analysis, however, also suggests that such regulations do not limit process timeframes to the 

targets specified. Even when limiting the analysis to projects eligible for expedited or fast-track 

review and to systems sizes of 50 kW and under, we find that interconnection process delays are

common and can range from days to several weeks.
22

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Our study is a first step toward filling a significant gap in the literature on distributed PV 

interconnection costs and time requirements. Further research, for example via in-depth 

interviews with installers and utilities, could help to identify the exact sources of delays in 

various processes and inform the development of policies and practices that minimize the 

amount of time required of utilities and installers for PV deployment. Also, follow-on analysis 

informed by additional data sources—such as internal utility project tracking systems, regulatory 

databases,

22 and further data from PV installers—would enable the comparison of 

interconnection times more broadly.

 22 There is an emerging focus on data transparency for interconnection timelines and queues. States such as 

California, Massachusetts, and New York require utilities to provide varying levels of information related to 

application processing times and volume. Some data are made publically available, often quarterly, to support data 

access and transparency in the interconnection process.
23

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

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26

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Appendix A: Interconnection Process Times for Large 

Commercial and Industrial Samples

Data for system sizes greater than 50 kW are much more limited, reducing the ability to draw 

robust conclusions. As a result, these statistics are included here rather than in the main body of 

the report. Overall, application and PTO timeframes are greater for the industrial sample (250 

kW to 2 MW) compared to the large commercial sample (50 to 250 kW). Median application 

timeframes are 51 business days for the the industrial sample and 15 days for the large 

commercial sample. For PTO, median timeframes are 18 days for the industrial sample and 10 

days for the large commercial sample. While these results are statistically different from the 

residential and small commercial samples, they are not statistically different from each other 

(i.e., between the industrial and large commercial categories). As in the the residential and small 

commercial samples, the range of values for application review and approval is larger than the 

range for PTO, indicating that, across all system sizes, there is a greater variance in application 

completion timeframes compared to PTO timeframes.

Figure 12. Days for application review and approval and PTO, full U.S. samples of large 

commercial (50 to 250 kW) and industrial (250 kW to 2 MW) systems

Application Review and Approval

System Size Mean Median Std. Dev Sample Size

Large Commercial (50 to 250 kW) 57 15 56 11

Industrial (250 kW to 2 MW) 66 51 55 23

Permission to Operate

System Size Mean Median Std. Dev Sample Size

Large Commercial (50 to 250 kW) 18 10 23 41

Industrial (250 kW to 2 MW) 24 18 20 58
27

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Appendix B: Interconnection Process Diagrams for 

Analyzed States with Timeframe Regulations for both 

Application Review and Approval and PTO (New York, 

New Jersey, and Colorado)

23

 23 Additional interconnection tracks exist in each state; only expedited or fast-track reviews are shown here.
28

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29

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
30

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
31

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.
32

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Appendix C: Statistical Difference in Means between 

States and Sizes for Different Interconnection 

Processes for the Full Sample of Systems (0–50 kW)

AZ CA CO NJ NY

CA 0.00 - - - -

CO 0.00 0.00 - - -

NJ 0.00 0.00 0.00 - -

NY 0.00 0.42 0.00 0.00 -

US 0.00 0.00 0.00 0.00 0.86

AZ CA CO NJ NY

CA 0.00 - - - -

CO 1.00 0.08 - - -

NJ 1.00 0.75 1.00 - -

NY 0.65 0.00 0.16 0.20 -

US 0.01 0.00 1.00 1.00 0.01

AZ CA CO NJ NY

CA 0.00 - - - -

CO 0.00 0.00 - - -

NJ 0.01 0.00 0.65 - -

NY 0.06 0.00 1.00 1.00 -

US 0.00 0.00 0.00 0.00 0.00

AZ CA CO NJ NY

CA 0.00 - - - -

CO 0.18 0.01 - - -

NJ 0.45 0.18 0.98 - -

NY 0.00 0.00 0.00 0.00 -

US 0.00 0.96 0.01 0.21 0.00

AZ CA CO NJ NY

CA 0.07 - - - -

CO 0.00 0.00 - - -

NJ 0.00 0.00 0.00 - -

NY 0.58 0.16 0.00 0.00 -

US 0.00 0.00 0.00 0.00 0.00

Total Project Days

Application Days

Construction Days

Inspection Days

PTO Days