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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

Technical Report

NREL/TP-6A20-72038

February 2019

New Approaches to Distributed PV 

Interconnection: Implementation 

Considerations for Addressing 

Emerging Issues

Richard McAllister,

1 David Manning,1 Lori Bird,2

Michael Coddington,2 and Christina Volpi2

1 Western Interstate Energy Board

2 National Renewable Energy Laboratory
NREL is a national laboratory of the U.S. Department of Energy

Office of Energy Efficiency & Renewable Energy

Operated by the Alliance for Sustainable Energy, LLC

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

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303-275-3000 • www.nrel.gov

Technical Report

NREL/TP-6A20-72038

February 2019

New Approaches to Distributed PV 

Interconnection: Implementation 

Considerations for Addressing 

Emerging Issues

Richard McAllister,

1 David Manning,1 Lori Bird,2

Michael Coddington,2 and Christina Volpi2

1 Western Interstate Energy Board

2 National Renewable Energy Laboratory

Suggested Citation

McAllister, Richard, David Manning, Lori Bird, Michael Coddington, and Christina Volpi. 

2019. New Approaches to Distributed PV Interconnection: Implementation Considerations 

for Addressing Emerging Issues. Golden, CO: National Renewable Energy Laboratory. 

NREL/TP-6A20-72038. https://www.nrel.gov/docs/fy19osti/72038.pdf.
NOTICE

This work was authored in part by the National Renewable Energy Laboratory, operated by Alliance for Sustainable 

Energy, LLC, for the U.S. Department of Energy (DOE) under Contract No. DE-AC36-08GO28308. Funding 

provided by the U.S. Department of Energy Office of Energy Efficiency and Renewable Energy Solar Energy 

Technologies Office, through the Western Interstate Energy Board. The views expressed in the article do not 

necessarily represent the views of the DOE or the U.S. Government.

This report is available at no cost from the National Renewable 

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

U.S. Department of Energy (DOE) reports produced after 1991 

and a growing number of pre-1991 documents are available 

free via www.OSTI.gov.

Cover Photos by Dennis Schroeder: (clockwise, left to right) NREL 51934, NREL 45897, NREL 42160, NREL 45891, NREL 48097, 

NREL 46526.

NREL prints on paper that contains recycled content.
iv

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Acknowledgments

The authors thank Michele Boyd and the Solar Energy Technologies Office (SETO) of the U.S. 

Department of Energy for their support of this work. This work was prepared by the Western 

Interstate Energy Board (WIEB) and the National Renewable Energy Laboratory (NREL) under 

FIA-17-1836. We are grateful for the technical editing provided by Jarett Zuboy. We also wish

to acknowledge early research support provided by Emerson Reiter, and the research support and 

contributions of Sydney Forrester. We thank our Technical Advisory Committee (TAC) 

members for their input on the research plan and report: Nonso Chidebell-Emordi (Arizona 

Corporation Commission), Erika Larsen (Arizona Public Service), Erica McConnell and Sky 

Stanfield (Interstate Renewable Energy Council), Michael Conway (Borrego Solar), Jason 

Minalga (ITC Transmission Co.), Ken Nichols (EQL Energy), and Nick Perugini (New Energy 

Colorado). We would also like to thank the following individuals for their review of this work:

Steven Coley and Lindsey Rogers (Electric Power Research Institute), Daniel Haughton

(Arizona Public Service), Debbie Lew (General Electric), Jaquelin Cochran and Eric Lockhart 

(NREL), Lisa Schwartz (Lawrence Berkeley National Laboratory), Sky Stanfield (IREC), Ken 

Wilson (Western Resource Advocates), and Sahm White (Clean Coalition).
v

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List of Acronyms

AC alternating current

CAISO California Independent System Operator

CEC California Energy Commission

CPUC California Public Utilities Commission

DC direct current

DG distributed generation

DER distributed energy resource

DERAC Distributed Energy Resource Avoided Cost (model)

DRP distribution resource planning

DRV demand reduction value

EPRI Electric Power Research Institute

EV electric vehicle

FDEMS facility distributed energy resource management system

FERC Federal Energy Regulatory Commission

HCA hosting-capacity analysis

HECO Hawaiian Electric Company

ICA integration capacity analysis

IEC International Electrotechnical Commission

IEEE Institute of Electrical and Electronics Engineers

IOU investor-owned utility

IREC Interstate Renewable Energy Council 

ISO-NE New England Independent System Operator

LNBA locational net benefits analysis

LSRV locational system relief value

NERC North American Electric Reliability Corporation

NEM net energy metering

NREL National Renewable Energy Laboratory

NWA nonwires alternatives

PG&E Pacific Gas and Electric

PSC Public Service Commission

PV photovoltaic(s)

REV Reforming the Energy Vision

SCE Southern California Edison

SDG&E San Diego Gas and Electric

SETO Solar Energy Technologies Office

SGIP Small Generator Interconnection Procedures

SIWG Smart Inverter Working Group

SRD source requirements document

TAC Technical Advisory Committee

UL Underwriters Laboratories

WDAT Wholesale Distribution Access Tariff

WIEB Western Interstate Energy Board
vi

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Executive Summary

In recent years, the rapid adoption of customer-sited photovoltaics (PV) and other distributed 

energy resources (DERs) has led to a variety of innovations and new approaches in assessing 

costs, grid conditions, and requirements for interconnecting DERs to the grid. Large volumes of 

interconnection requests in some states and utility service areas have led to a renewed focus on 

equity, cost, efficiency, and transparency throughout various stages of the interconnection 

process.

This report examines new policies and practices for interconnecting residential and commercial 

PV systems that are being implemented by states and utilities nationally to address emerging 

challenges with the increased volume of interconnection requests. The experience and lessons 

learned by these jurisdictions can prove useful to other regulators, policymakers, and utilities 

attempting to address similar challenges. This work builds on an earlier study (Bird et al. 2018) 

that reviewed interconnection practices and costs across the western states by providing more indepth discussion of the design and implementation considerations of new interconnection 

policies and practices to share lessons learned. Both reports were developed as part of a larger 

joint project between the Western Interstate Energy Board and the National Renewable Energy 

Laboratory, funded by the U.S. Department of Energy’s Solar Energy Technologies Office, that 

examines barriers to distributed PV deployment in the 11 states within the Western 

Interconnection.

Issues covered here include understanding and allocating costs, evaluating grid conditions to 

inform PV siting, interconnecting PV plus storage, automating processes, and requiring the 

availability of advanced-inverter functions that can address grid concerns with greater 

penetrations of distributed, inverter-based resources. New interconnection policies and practices 

are being adopted or piloted in the following areas by states and utilities:

• Cost certainty—A few states have implemented policies to help increase cost certainty for 

DER customers by having utilities provide cost estimates earlier in the process and limiting 

the customer’s liability for upgrade costs to within a certain percentage (e.g., plus 25% of 

estimated costs) of the utility’s upgrade cost estimate (Massachusetts and California). For 

smaller DER systems, some utilities provide certainty through fixed interconnection costs.

• Cost allocation—To address equity issues in the allocation of upgrade costs, several utilities 

and states are implementing new approaches to allocating costs of grid upgrades across 

projects (either a group of projects or across current and future projects), rather than 

imposing costs on a single project that triggers an upgrade. 

• PV coupled with storage interconnection—With rapidly falling storage costs and greater 

interest in installing PV coupled with storage, several states are developing detailed standards 

that address the dispatch and operation of a combined PV and storage system. Evaluating 

grid impacts of PV systems coupled with storage can be more complex than for standalone 

PV because storage can operate as both a load and a generator and can have different grid 

impacts depending on how it is operated. 

• Hosting capacity—Several states and utilities have undertaken processes to assess the grid 

hosting capacity, or the amount of distributed PV and other DERs that can be installed on a 

portion of the distribution system without triggering violations or grid upgrades. Hostingcapacity analysis can be more accurate than the rule-of-thumb approaches often used in 
vii

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technical screens. California has undertaken a detailed analysis approach with an eye toward 

using the data to expedite interconnection and to aid in distribution system planning. New 

York, Hawaii, and Minnesota also have undertaken hosting-capacity assessments to aid in 

distribution-system planning and to provide potential DER projects with more information 

about grid conditions in advance of project initiation. New standards and codes—such as 

IEEE 1547-2018 and UL 1741SA—could positively impact hosting capacity on a significant 

number of feeders, especially when voltage excursions are the main area of concern. Smart 

inverters are required in California, Hawaii, and Massachusetts and in all likelihood will have 

a positive impact on the overall hosting capacity of many utility feeders. Additionally, DER 

technologies such as energy storage systems also might improve hosting-capacity limits by 

constraining the exports of distributed-generation DERs. 

• Locational value—Some areas are developing methods to assess the locational value of PV 

and other DERs to identify locations where they could defer or avoid grid upgrades or 

provide grid services. Both New York and California are assessing locational value of DER.

New York also has incorporated locational value elements in its value stack tariff for 

compensating exported power from DER, but commission staff are re-evaluating and 

assessing current approaches. Several other states are beginning to evaluate the opportunities 

that could arise with the use of nonwires alternatives (NWA) that could supplant some 

distribution, substation, and even transmission expansion plans. 

• Advanced inverters—Several states are developing standards or requirements to take 

advantage of the functionality that advanced inverters can provide to contribute to grid 

reliability and communication with utilities. California, Hawaii, and Massachusetts now 

require all interconnecting DERs to have advanced inverters that can perform several

functions (e.g., voltage and frequency ride-through, reactive power support—provided using 

UL 1741SA–listed inverters) to enhance grid reliability and improve coordination between 

DERs and system operators. ISO New England also has developed standards for inverterbased generation greater than 100 kW, and Hawaii requires ride-through capability for gridconnected inverters. 

• Automation—A variety of utilities that have experienced rapid growth in interconnection 

requests have undertaken efforts to streamline interconnection processes, often by 

implementing new software applications that increase automation and reduce processing 

time. Several utilities have reported significant labor cost savings and increased efficiency as 

a result of these changes. 

The growing volume of interconnection requests has driven these new policies and practices in 

many instances. Jurisdictions that anticipate future growth might be able to learn from the 

experience of areas that have encountered challenges associated with rapid adoption and 

potentially could avoid some challenges before they emerge. 
viii

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Table of Contents

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

2 Cost Certainty Policies ........................................................................................................................ 2

2.1 Status and Experience to Date....................................................................................................... 2

2.1.1 Cost Envelope .................................................................................................................. 2

2.1.2 Fixed Costs....................................................................................................................... 4

2.1.3 Standardized Costs—Unit Cost Guide............................................................................. 5

2.1.4 Tracking and Reporting Policies...................................................................................... 5

2.2 Lessons Learned: Design and Implementation Considerations..................................................... 6

2.2.1 Paying for Cost Overruns................................................................................................. 6

2.2.2 Establishing a Cost Range................................................................................................ 7

2.2.3 Transparency and Reporting ............................................................................................ 7

2.3 Summary and Key Considerations................................................................................................ 7

3 Cost Allocation ..................................................................................................................................... 9

3.1 Status and Experience to Date....................................................................................................... 9

3.1.1 Cluster Study and Group Cost-Allocation Approaches.................................................... 9

3.1.2 Reimbursement from Future Projects............................................................................. 10

3.1.3 Other Utility Approaches to Cost Allocation................................................................. 10

3.2 Lessons Learned: Design and Implementation Considerations................................................... 12

3.2.1 Equitably Allocating Costs Across a Group of Projects ................................................ 12

3.2.2 Addressing Repayment Risk .......................................................................................... 12

3.2.3 Locational Factors in Equitably Allocating Costs Across Categories of Projects ........ 13

3.3 Summary and Key Considerations.............................................................................................. 13

4 Interconnection of Standalone Storage and PV Coupled with Storage....................................... 14

4.1 Status and Experience to Date..................................................................................................... 14

4.2 Lessons Learned: Design and Implementation Considerations................................................... 15

4.2.1 Treatment of Storage Load............................................................................................. 15

4.2.2 Storage Operation and Control....................................................................................... 15

4.2.3 Treatment of Combined PV and Storage Capacity for Interconnection Review .......... 16

4.2.4 Net-Metering Compensation.......................................................................................... 17

4.2.5 Storage Metering............................................................................................................ 18

4.3 Summary and Key Considerations.............................................................................................. 18

5 Hosting Capacity ................................................................................................................................ 19

5.1 Status and Experience to Date..................................................................................................... 19

5.1.1 Screening Approaches.................................................................................................... 19

5.1.2 California Investor-Owned Utility Hosting-Capacity Analysis and Map ...................... 20

5.1.3 Hosting-Capacity Analysis and Mapping in Other States.............................................. 22

5.2 Lessons Learned: Design and Implementation Considerations................................................... 23

5.2.1 Intended Uses................................................................................................................. 23

5.2.2 Methods and Data Accuracy .......................................................................................... 23

5.2.3 Frequency of Updates and Public Accessibility of Information .................................... 24

5.2.4 Cost Considerations........................................................................................................ 24

5.3 Summary and Key Considerations.............................................................................................. 24

6 Locational Value ................................................................................................................................. 26

6.1 Status and Experience to Date..................................................................................................... 26

6.1.1 California’s Use of Locational Value............................................................................. 26

6.1.2 Assessment of DER Deferral Value in California.......................................................... 28

6.1.3 New York’s Use of Locational Value ............................................................................ 29

6.2 Lessons Learned: Design and Implementation Considerations................................................... 30

6.2.1 Defining Objectives of Locational Value Analysis........................................................ 30
ix

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6.2.2 Methods for Assessing Locational Values..................................................................... 31

6.2.3 Categories of Locational Benefits.................................................................................. 31

6.2.4 Using Locational Value to Drive DER Investments...................................................... 31

6.3 Summary and Key Considerations.............................................................................................. 31

7 Advanced-Inverter Requirements..................................................................................................... 33

7.1 Status and Experience to Date..................................................................................................... 33

7.1.1 National Standards......................................................................................................... 33

7.1.2 California’s Smart Inverter Working Group Process..................................................... 34

7.1.3 Experiences of Other Jurisdictions with Advanced Inverters........................................ 36

7.2 Lessons Learned: Design and Implementation Considerations................................................... 37

7.2.1 Inverter Replacements and Cost Considerations............................................................ 37

7.2.2 Jurisdictional Authority.................................................................................................. 38

7.3 Summary and Key Considerations.............................................................................................. 38

8 Application Automation and Process Improvements..................................................................... 39

8.1 Status and Experience to Date..................................................................................................... 39

8.2 Approaches to Process Improvements and Automation.............................................................. 39

8.3 Design and Implementation Considerations................................................................................ 41

8.4 Summary and Key Considerations.............................................................................................. 41

9 Summary and Conclusions ............................................................................................................... 42

References................................................................................................................................................. 45

Appendix. Other Functions Advanced Inverters Must Perform Autonomously Under CPUC Rules54

List of Figures

Figure 1. Portion of SCE service territory with hosting-capacity results, from publicly available DRP 

map......................................................................................................................................... 21

Figure 2. Portion of SDG&E service territory from publicly available LNBA map .................................. 27

Figure 3. Example of LSRV-eligible area map of IOU ConEd for Borough of Brooklyn ......................... 30

Figure 4. Western utility application submission pathway ......................................................................... 39

List of Tables

Table 1. States with Cost Envelopes............................................................................................................. 4

Table 2. Example System Equipment Costs from Unit Cost Guide ............................................................. 5

Table 3. Example Xcel Monthly Cost Variance Report, November 2017...................................................... 6

Table 4. Utility Application Processing Improvements.............................................................................. 40
1

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1 Introduction

As the cost of installing distributed photovoltaics (PV) has fallen, the number of requests to 

interconnect PV systems to distribution grids has risen substantially in many utility service areas. 

Between 2013 and 2017, the number of PV systems interconnected to U.S. distribution grids

more than tripled (EIA 2017; Makhyoun et al. 2014). Many of these PV systems have been 

installed in the western United States (the West), particularly in California, Arizona, Colorado, 

Nevada, and Utah. Growth in the number of interconnection requests to utilities—for PV and 

other distributed energy resources (DERs)1—is raising discussions about how to address 

interconnection costs, streamline the various processes, manage new technologies, and provide 

transparency around utility grid-related concerns.

States and utilities are modifying their interconnection practices to address new DER challenges. 

For example, some states are addressing concerns about uncertainty in costs associated with the 

interconnection process. Additionally, some states and utilities are implementing new approaches 

to inform customers and installers about grid conditions and the potential costs and benefits of 

siting PV and other DERs in various grid locations. Emerging technologies, such as battery 

storage coupled with PV, are also leading to new requirements because these combined systems 

could present more complex interactions with distribution systems and the grid as a whole. 

Further, many utilities have implemented processes to streamline interconnection procedures—

such as through automation, software upgrades, and organizational changes—to handle larger 

volumes of requests. 

This report examines emerging issues associated with interconnecting residential- and 

commercial-scale PV to facilitate sharing of lessons learned and best practices across 

jurisdictions. It covers issues related to allocating and understanding costs, understanding grid 

conditions to inform PV siting, interconnecting storage, automating processes, and requiring the 

availability of advanced-inverter functions that could help increase PV hosting capacity. This 

report builds on an earlier study that reviews interconnection practices and costs across the West

(Bird et al. 2018). Both reports were developed as part of a larger joint project between the 

Western Interstate Energy Board and the National Renewable Energy Laboratory—and funded 

by the U.S. Department of Energy’s Solar Energy Technologies Office—that examines barriers 

to distributed PV in the 11 states within the Western Interconnection.

The remainder of the report is structured as follows: Section 2 discusses state policies designed 

to improve the transparency and certainty of interconnection costs early in the process. Section 3

explores challenges related to equitably allocating costs as well as approaches that have been 

used in other related contexts or jurisdictions. Section 4 addresses the emerging issues related to 

interconnecting PV coupled with storage. Section 5 explores efforts by states and utilities to 

develop information and maps showing the grid’s capability to host PV and other DERs. Section 

6 discusses policies being developed to assess the locational value of distributed PV. Section 7

covers the policies being developed to exploit the functionality of advanced PV inverters.

 1 Other types of DER include fuel cells, combined heat and power, distributed wind, storage, biomass facilities, and 

internal combustion engines. 
2

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2 Cost Certainty Policies

Under interconnection rules in most western states, customers installing systems bear most 

interconnection costs—including study costs, such as the cost of supplemental review or detailed 

impact studies, and distribution system upgrade costs. Often customers do not know the full cost 

of interconnection until late in the interconnection process after substantial time and money are 

invested. The uncertainty of costs can make it difficult to assess the economic viability of 

projects and also can make it challenging to obtain project financing. Interconnection costs might

be significant if impact studies or system upgrades are required to interconnect a project safely 

and reliably. 

For supplemental review and detailed studies, typically the utility estimates the cost of the study,

and the developer submits a study deposit. Once the study is completed, the developer pays any 

difference between the deposit and final study costs. Generally, if the utility determines that 

distribution system upgrades are required to interconnect a project safely, it provides the project 

developer with an estimate of upgrade costs. If the developer decides to go forward with the 

project, it signs an interconnection agreement and is liable for all upgrade costs, even if they 

exceed the initial utility estimate.

As distributed PV penetrations increase in many states, it also becomes more likely that an 

interconnection request will require detailed impact studies that could trigger distribution-system 

upgrades. In response to these concerns, some states have developed policies to help provide 

more certainty about interconnection costs earlier in the process, which potentially can help 

developers plan and execute PV installations more efficiently and at lower cost.

2.1 Status and Experience to Date

States and electric utilities have deployed several different methods to address challenges 

surrounding the uncertainty of interconnection upgrade costs, which are described below.

2.1.1 Cost Envelope

A cost envelope limits a developer’s cost responsibility for upgrades (or modifications) to a 

certain threshold above a utility’s estimate. Some states have implemented a cost-envelope 

requirement or option (Table 1). In these instances, utilities estimate costs early in the 

interconnection process based on a preliminary assessment of interconnecting the project to the 

distribution grid. Typically, costs are estimated before a developer signs an interconnection 

agreement, and these estimates generally are made without a site visit. This expedites application 

review but could reduce the accuracy of estimates (CPUC 2016b, 30–31). 

Massachusetts and California have binding cost envelopes that limit developer upgrade cost 

liability, although California’s program is currently an opt-in pilot and, to the authors’ 

knowledge, very few projects have used the cost envelope. In Massachusetts, once a utility has 

conducted an impact study that includes a cost estimate, a developer can sign an Early 

Interconnection Service Agreement to limit its liability to 25% above the impact study cost 

estimate (MDPU 2009, 14; MDPU 2015, 115). After the utility produces another cost estimate 

based on a detailed study, developers only are liable for actual upgrade costs up to 10% more 

than the detailed study estimate (MDPU 2009, 76). Utility shareholders are financially 
3

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responsible for costs that exceed the envelope (MDPU 2009 76; Greentech Media 2017).

2

California’s pilot allows developers to opt into a 25% cost envelope. To participate, a developer 

must pay an additional $2,500 and allow the utility 20 additional business days to develop a

more rigorous upgrade cost estimate (CPUC 2016b, 30).3

Oregon and Utah also use cost envelopes, although neither grants as much cost certainty as the 

programs in California and Massachusetts. Oregon’s net energy metering (NEM) interconnection 

rules specify a nonbinding 25% cost envelope for system upgrades. This does not improve cost 

certainty but might give developers an opportunity to dispute significant cost overruns (Oregon 

PUC n.d.). Utah’s interconnection rules stipulate a cost-certainty threshold for the costs 

associated with supplemental review and detailed studies. A developer is only liable for up to 

25% more than a utility’s “nonbinding good faith estimate” of study costs (Utah Office of 

Administrative Rules 2018); cost overruns are absorbed by the utility and recovered via the rate 

base. Outside of the West, New York and Minnesota also have nonbinding cost estimates. New 

York’s interconnection requirements state that “[c]ontingencies associated with the cost 

estimates shall not exceed +/- 25%,” but the requirements do not specify who is responsible for 

paying for cost overruns (NY PSC 2018, 14). In Minnesota, the Public Utility Commission 

requires Xcel to report community solar projects where actual costs are +/- 20% of estimated 

costs (see section 2.1.4 Tracking and Reporting Policies for a more detailed discussion) 

(Minnesota PUC 2016a, 10).

 2 An issue with this approach is that it could create a financial incentive for utilities to overestimate potential costs to 

protect shareholders from potential cost overruns. However, it nevertheless provides the developer with additional 

cost certainty.

3 Because NEM projects up to 1 MW are not liable for grid-upgrade costs, the pilot only applies to NEM projects 

> 1 MW and non-NEM facilities that are under California’s Rule 21 jurisdiction.
4

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Table 1. States with Cost Envelopes

State Envelope

Entity Financially 

Responsible for 

Overrun

Systems That Can/Must 

Participate

Massachusetts Cost envelope for NEM

interconnections.

25% upgrade cost 

envelope after impact 

study estimate.

10% upgrade cost 

envelope after detailed 

study estimate.

Utility shareholders Net-metered systems

California 5-year pilot program.

Developers can opt into 

a 25% upgrade cost 

envelope. 

To opt in, a developer 

must pay a $2,500 

deposit and allow the 

utility additional study 

time.

Utility shareholders or 

ratepayers

Systems reviewed for 

interconnection via fast 

track or independent study 

track (net-metered 

systems ≤ 1 MW have no 

upgrade cost 

responsibility; see section 

2.1.2 Fixed Costs)

Oregon State NEM rules 

stipulate that actual 

interconnection costs 

should be within 25% of 

estimated costs.

The cost envelope is not 

binding—it is a target, 

not a requirement.

None (not financially 

binding)

Net-metered systems

Utah A developer’s liability for 

studies is limited to 25% 

more than the utility’s 

study cost estimate.

Ratepayers All interconnection 

requests where studies 

are required

2.1.2 Fixed Costs

Some jurisdictions establish a fixed interconnection fee for certain classes of systems, which can 

cover a range of costs, including application processing costs, study costs, and in some cases 

upgrade costs. Often, interconnection fees are fixed for small residential projects, but some 

jurisdictions fix fees for commercial systems as well (e.g., up to 1 MW). Such a policy allows a 

developer to pay a fixed amount to cover technical study and/or upgrade costs.

Under California’s Rule 21, NEM applicants with projects of 1 MW or smaller pay a fixed 

interconnection request fee, which varies by utility and is based on the utility’s historic average 

processing, administrative, meter installation, and study costs for interconnection requests

(CPUC 2016d).

4 Under the program for NEM projects, applicants are not liable for 

 4 PG&E also currently is evaluating a pilot to adopt the fixed-cost approach for non-NEM projects ≤ 1 MW.
5

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interconnection study costs or for distribution system or transmission network upgrade costs; 

upgrade costs are covered by ratepayers (PG&E 2017, 51–52, 57). For these NEM customers, 

cost responsibility is capped at the fixed fee, even if lengthy impact studies or significant grid 

upgrades are required. In addition to providing cost certainty for applicants, this fixed fee can 

help streamline the application process for utilities, as utility staff do not have to assign unique 

cost allocations to each residential and commercial project.

In Nevada, Rule 15 notes that if grid upgrades are required to interconnect a DER system, 

interconnection cost responsibility is determined using a “fixed price” or “actual cost” 

arrangement (NV Energy 2018a, 13). Cost responsibility depends on the upgrade cost estimate: 

if the estimate is less than $40,000, the developer is only responsible for a fixed-price quote. For 

projects with upgrade cost estimates of more than $40,000, the developer is responsible for 

actual costs (NV Energy 2013, 38).

2.1.3 Standardized Costs—Unit Cost Guide

A standardized cost guide can provide greater transparency around upgrade costs and help 

developers estimate likely costs. California investor-owned utilities (IOUs) are required to 

develop publicly available unit cost guides, which are updated annually, and provide the 

estimated cost of various common types of equipment required for upgrades (Table 2; CPUC 

2016b, 7, 19).

5 Although a utility is not bound to interconnect systems at the estimated costs, the 

guides help to improve a developer’s understanding of potential upgrade charges, evaluate the 

reasonableness of estimates or final costs, and provide some measure of comparability between 

project estimates.

Table 2. Example System Equipment Costs from Unit Cost Guide

Equipment Unit Cost

Grounding/stabilizing transformer—pole 

mounted

$30,000

Grounding/stabilizing transformer—pad 

mounted

$51,000

Conductor—overhead-urban $220/ft

Reconductor—overhead-rural $130/ft

Relocate capacitor bank $18,000

Regulator control settings modifications $2,500

Relocate voltage regulator $50,000

Recreated from PG&E 2018

2.1.4 Tracking and Reporting Policies

Tracking and reporting interconnection costs provides transparency around the accuracy of cost 

estimates. For example, in response to a dispute between a developer and Xcel Minnesota 

regarding a project in which actual costs significantly exceeded the expedited detailed study cost 

 5 Utility distribution level unit cost guides: PG&E, SCE, SDG&E.
6

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estimate,6 the Minnesota Public Utilities Commission issued an order in November 2016 

allowing the commission to gather data on the variance between Xcel’s upgrade cost estimates 

and actual costs (Minnesota PUC 2016a, 10). Xcel is required to submit a monthly report on 

estimates and actual upgrade costs for community solar-garden program projects. When actual 

costs diverge from estimates by more than 20%, Xcel must explain the variance (Table 3).

Table 3. Example Xcel Monthly Cost Variance Report, November 2017

Project

Estimated 

Cost Actual Cost Variance Explanation

1

$67,500 $129,966 93%

Distribution required additional 

mobilization. Telemetry needed.

2 $12,800 $12,797 0% Within 20%.

3 $1,351,000 $1,029,599 -24% Distribution was completed using a 

shorter route. Telemetry used 

cellular technology.

4 $192,750 $220,941 15% Winter construction. Telemetry used 

cellular technology.

Adapted from Xcel Energy 2017d, 7

2.2 Lessons Learned: Design and Implementation Considerations

There are a few key decision points for policymakers in designing a program that improves cost 

certainty, allocates risk reasonably, and recognizes the challenges utilities face in producing 

accurate cost estimates. Furthermore, promoting transparency around cost estimates and actual 

upgrade costs, such as through data collection or itemizing upgrade costs, can help inform 

policymaking.

2.2.1 Paying for Cost Overruns

Under cost certainty measures in place today, such as a fixed-cost provision or a cost envelope, 

cost overruns are passed on to utility ratepayers, shareholders, or some combination of both. 

Passing costs to shareholders could create a stronger incentive for the utility to develop accurate 

estimates because cost overruns would erode profits. Reporting requirements for estimated and 

actual costs can also encourage accuracy in estimation.

Additionally, although holding the utility accountable for all system upgrade costs above a 

certain fixed-cost or cost-envelope threshold enhances developer cost certainty, this could 

unfairly burden the utility if cost overruns are due to factors outside the utility’s control. As 

highlighted in Xcel Minnesota’s monthly cost report (Table 3), there can be significant variance 

between estimates and actual costs.

California addresses this concern by holding utility shareholders responsible for cost overruns 

deemed to be under a utility’s control while allowing the utility to recover cost overruns deemed 

outside of its control. California’s pilot specifies the “Cost Envelope shall only apply to the 

interconnection costs that are under the utilities’ control and should be thus reasonably expected 

 6 Xcel Minnesota offers developers an “indicative cost estimate” that allows developers to obtain an interconnection 

agreement on an accelerated timeline for projects requiring detailed study.
7

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to be estimated within 25% accuracy” (CPUC 2016b, 30). To incorporate this into the pilot, 

utility shareholders are not held responsible for cost overruns that were “prudently incurred” and 

subject to a reasonableness review (CPUC 2016b, 34). In addition to a reasonableness review, 

California’s cost-envelope pilot also specifically notes that costs related to permitting, siting, and 

environmental review are the responsibility of the developer (CPUC 2016b, 33). This design 

seeks to fairly allocate cost overruns to the entity deemed responsible.

However, these approaches are not an exhaustive list of potential strategies for allocating 

responsibility for cost overruns. For example, developers could pay into a joint balancing 

account that covers upgrades that increase hosting capacity on a feeder or could potentially 

benefit a group of projects. Alternatively, payments into a balancing account could act as a form 

of insurance that helps cover a portion of the risk of cost overruns. Although neither approach 

has been implemented, both are potential alternatives that spread the risk of cost overruns over a 

group of projects.

2.2.2 Establishing a Cost Range

A cost envelope balances cost-certainty benefits provided to the project developer against the 

challenges utilities face in making accurate estimates prior to conducting a detailed study. Most 

jurisdictions have used a 25% cost threshold, although Massachusetts uses a 10% threshold after 

a detailed study is conducted. In determining the magnitude of the envelope, policymakers could 

consider whether additional study, which, for example, could allow the utility to conduct a site 

visit, could help increase the cost certainty of a utility estimate.

2.2.3 Transparency and Reporting

Policies promoting data collection and transparency create a framework to improve cost certainty

without impacting cost liability. Section 2.1.4 discusses Xcel Minnesota’s reporting. As another 

example, California’s cost-envelope pilot requires utilities to submit quarterly reports on 

differences between estimates and actual costs, as well as information on the cost of providing a 

more detailed estimate for the cost envelope. This information is meant to help improve the 

accuracy of cost estimates (CPUC 2016b, 39). Similarly, unit cost guides provide developers 

with more information about cost expectations earlier in the interconnection process and improve 

accountability without limiting a developer’s upgrade cost liability.

Hosting-capacity maps (discussed in detail in Section 5) provide a visual representation of areas 

of the system that can accommodate additional distributed generation (DG) capacity. These 

increase transparency by improving developer visibility into the grid. Although this information 

does not limit developer liability, it helps developers target areas of the system where upgrades 

are less likely to be required to connect a project to the grid, thus reducing the likelihood that 

upgrades are required. Additionally, this facilitates a more efficient use of existing distribution 

infrastructure because it encourages developers to target existing available capacity.

2.3 Summary and Key Considerations 

Several approaches have been used to provide customers with more transparency and certainty 

about interconnection costs. A few key considerations in designing and implementing these 

policies are the following:
8

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

• A fundamental challenge is balancing the utility’s difficulties in estimating interconnection 

costs early in the process with the customer’s desire for cost certainty. In designing a costenvelope threshold (e.g., 25%), an important consideration is the amount of utility study 

required to develop an accurate cost estimate.

• Prestudy of grid interconnection hosting capacity provides valuable information and can be 

useful in quickly estimating whether upgrades are required and the nature of those upgrades, 

helping to refine cost estimates.

• In designing a cost-envelope or fixed-cost provision, a key issue is whether to hold utility 

shareholders responsible or allow cost overruns to be recovered from the rate base. 

Considerations include creating an incentive for accurate utility cost estimates and not unduly 

holding a utility’s shareholders or ratepayers responsible for costs beyond the utility’s

control.

• Providing developers with detailed information on potential upgrade costs earlier in the 

interconnection process—such as through a unit cost guide or fixed fee—can improve 

developer expectations of upgrade costs. Additionally, informing developers about potential 

upgrade requirements based on the location of the proposed DER relative to the substation, 

loads, and other factors on the circuit, such as through hosting-capacity analysis, also can 

inform siting decisions.

• Collecting data on the variance between estimated and actual costs could help improve 

accuracy over time and can inform interconnection practices.
9

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

3 Cost Allocation

In addition to improving cost certainty, alternative approaches to allocating interconnection costs 

can reduce the cost burden on developers. Distribution system upgrade costs required to 

interconnect a residential PV system—such as for a residential transformer upgrade—are in 

some cases absorbed by the utility and placed in the rate base. For commercial-sized and larger 

projects, however, if system upgrades are required to interconnect proposed projects safely, the 

common practice is to allocate costs to the “cost causer,” or the marginal project in the queue 

that triggers the distribution upgrades. With higher volumes of interconnection requests, more 

distribution upgrades likely will be needed to accommodate greater grid-hosting capacity. The 

“cost causer pays” principle incentivizes developers to utilize existing infrastructure before 

pursuing projects that require upgrades. However, this approach could pose an obstacle to PV 

deployment because a single project might unduly pay for costs that benefit other projects. 

Further, individual projects might be unable to absorb distribution upgrade costs, which could 

discourage development on feeders with higher penetrations. Innovative cost-allocation 

approaches could help overcome this barrier and also fairly allocate costs to the entities

(developers, ratepayers, the utility) that benefit from upgrades.

3.1 Status and Experience to Date

A few jurisdictions have implemented alternative cost-allocation strategies, which are described 

below.

3.1.1 Cluster Study and Group Cost-Allocation Approaches

California has a distribution group study process, under Rule 21 for IOUs, and a cluster study 

process, under the Wholesale Distribution Access Tariff (WDAT), both of which evaluate the 

grid impact and upgrade requirements of a group of projects in the interconnection queue (PG&E 

2016; PG&E 2017; SCE 2017). The distribution group study process is for projects that are 

electrically interdependent and could jointly trigger the need for upgrades but are not expected to 

impact the transmission system. The cluster study process is for systems that could have an 

impact on the California Independent System Operator (CAISO) jurisdictional transmission 

system. The two processes are used for larger commercial and ground-mount systems and might

not be relevant for smaller DER systems because of the time and cost required. Developers apply 

to a distribution group study through a semi-annual application window and the cluster study 

process annually; however, the latter review process can take multiple years. To the authors’ 

knowledge, the distribution group study process is rarely used and, although the cluster study 

process is used more frequently, it is generally used for multi-MW-sized projects.

When the upgrades required to interconnect a group are determined, upgrade costs are allocated 

across the group rather than to a single project, based in part on relative nameplate capacity and a 

proposed project’s contribution to the need for upgrades (PG&E 2017; SCE 2017).7 This costdistribution approach makes it less likely that interconnection applications stall when system 

upgrades are required. If a project drops out of the group, costs are reallocated to the remaining 

projects in the queue. Additionally, this could lead to the need to restudy the new group of 

projects, which could add to review time. 

 7 For a more detailed explanation of how costs are allocated, see PG&E (2017, 61) and SCE (2017, § 4.6.3).
10

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Massachusetts’ interconnection standards also include a group study process that is currently 

being refined through an open docket. Similar to California’s distribution group study process, a 

group of projects is studied jointly and costs for systems are allocated proportionally based on 

system sizes (MDPU 2016, 26). The process is currently undergoing review though an open 

docket.

8 Some stakeholders critiqued how long the group study process could take and that there 

were not standard timeline requirements. An initial utility filing in the proceeding noted that,

although coordinating study and upgrades for a group of projects increases complexity, it can 

reduce the overall time to interconnect projects relative to if they were processed individually 

(MDPU 2017).

3.1.2 Reimbursement from Future Projects 

As part of the Reforming the Energy Vision (REV) initiative, the New York Public Service 

Commission (PSC) is developing a cost-allocation mechanism to help address the “free-rider”

issue arising when one developer pays for system upgrades that subsequently accommodate 

additional projects due to increased grid-hosting capacity. A more detailed proposal is being 

developed so the PSC adopted an interim cost-sharing policy for substation-level upgrades. In 

essence, a developer that triggers upgrades is initially responsible for all upgrade costs, but future 

projects that can interconnect because of the upgrades will reimburse the initial project 

proportionally based on project size (NY PSC 2017a, 9–10). However, concerns remain about 

the risk of the developer investing in system upgrades not being reimbursed.

National Grid in New York is piloting another approach to distribution costs across a group of 

projects. It upgraded two substations to increase the system capacity available for DERs to 

accommodate currently queued and future project applications. Costs are allocated 

proportionally across all projects larger than 50 kW based on project size (the upgrade cost per 

kW is calculated for each substation), and the calculated rate is charged as a fee. Any upgrade 

costs not fully recovered through these fees can be rate-based by the utility (NY PSC 2017b). 

This approach gives more cost certainty for developers and allocates costs across a group of 

projects, and the repayment risk is borne by the utility (and in turn ratepayers) instead of by DER 

developers.

3.1.3 Other Utility Approaches to Cost Allocation 

Other utility approaches to cost allocation also could have relevance for determining appropriate 

mechanisms for addressing costs of DER. Both line extension policies and transmission 

infrastructure costs include approaches that spread costs across beneficiaries.

3.1.3.1 Utility Line Extension Policies

Cost allocation under utility line extension policies could provide a model for another alternative 

approach for addressing DER. Generally, utility line extension policies allow utilities to use a 

construction allowance to pay for limited line extensions, but costs exceeding the allowance are 

paid for by the builder/customer.

9 Future customers who benefit from the line also might share 

 8 Massachusetts Department of Public Utilities Docket 17-164. 9 For example, see service extension policies for Xcel Energy at https://www.xcelenergy.com/staticfiles/xe/PDF/WIMI-Partners-Builders-Service-Guide.pdf where natural gas and electric extensions require no charge (up to 300 feet 

in Wisconsin and up to 200 feet in Michigan) and for Colorado at https://www.xcelenergy.com/staticfiles/xe-
11

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the costs borne by the builder/customer. Cost allocation can vary by size of the line and type of 

utility (e.g., IOU, cooperative, municipal, other). The cost of a new service line extension for less 

costly upgrades within an urban setting often can be entirely covered by the construction 

allocation and rate-based. For example, a 100-foot section of distribution system with a 

transformer at the customer premise might be entirely covered by the utility, depending on a 

utility’s construction allowance formula,

10 and be placed in the rate base.

For longer line extension projects, the cost of a new service extension might not be fully covered

by the construction allocation, and the difference is paid by the builder/customer. For example, a 

1-mile section of distribution system could cost tens of thousands of dollars, and the calculated 

construction allowance would not cover the majority of the cost of that line extension. The utility 

could rate-base some of the line extension cost, depending on the construction allowance

formula, and the remainder of the costs would be borne by the customer,

11 and refunds could be 

applied during an Open Extension Period (e.g., under Advice No. 1663—Electric, 2/12/14, Xcel 

Energy Colorado will consider 10-year-eligible line extensions). If a second (and third, etc.) 

customer requires new service and can use the line paid for by the first customer, however, then 

the second customer would share the costs of the line extension under some utility policies; this

is the same approach that is taken in the New York PSC cost-allocation policy. Some types of 

utilities—such as cooperatives—might not provide a construction allowance, so the 

developer/customer would pay for most line extensions completed (other than large upgrades,

such as a main feeder or substation).

This line-extension policy approach could be used as a model for distribution upgrade cost 

allocation. The construction allowance customers can receive for a new line extension could pay 

for additional capacity on a new line to accommodate DERs. When a DER developer is required 

to pay for line upgrades, future DER developers that benefit from the new line, and grid-hosting 

capacity, could help defray those initial costs. A downside of this approach, which resembles the 

interim New York PSC policy, is that it still requires the developer that triggers the upgrades to 

shoulder the initial costs.

3.1.3.2 Transmission Infrastructure Costs

Cost allocation also applies to recovery of transmission infrastructure costs, which could be 

assigned to the generator or rate-based to the load. In general, costs associated with 

interconnection of a generation resource at the transmission level are initially assigned to the 

generator but subject to reimbursement from ratepayers over a five-year period if the generation 

remains in operation. Costs for transmission upgrades are often allocated based on the entities 

that benefit from the upgrades. ISOs allocate transmission upgrade costs a number of ways, for 

 

responsive/Working%20With%20Us/CO-PSCO-2017-BCL-Bulders-Guide.pdf (construction allowance varies - see 

page 16). Policies vary by utility and details can be found online for most larger IOUs.

10 Many utilities (primarily IOUs) provide a construction allowance for electric system extensions for new or 

upgraded services. The cost of a utility line extension might be paid for by the utility, in part or in total, based on the 

cost of materials and labor, which is reduced based on the expected sales of energy each year. 11 See Xcel Energy Extension Policy on page 5 at

https://www.xcelenergy.com/staticfiles/xe/Regulatory/Regulatory%20PDFs/CO-Extension-Policy-14AL-0137EAdvice-1663-Electric.pdf.
12

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example by allocating costs locally for lower-voltage upgrades or directly to beneficiaries.12

Additionally, Federal Energy Regulatory Commission (FERC) Order 1000 outlined principles 

for allocating transmission upgrade costs, which states that costs should be allocated “in a 

manner that is at least roughly commensurate with estimated benefits,” and entities that do not 

benefit should have cost responsibility for upgrades.13 Network-upgrade cost-allocation policy 

signals that, in electricity system planning, there is precedent for distributing costs across 

beneficiaries and not just to the project that triggers the need for an upgrade.

3.2 Lessons Learned: Design and Implementation Considerations

The design and implementation of cost-allocation policies have important implications related to 

fairness and risk.

3.2.1 Equitably Allocating Costs Across a Group of Projects

Allocating upgrade costs across a group of projects reduces the likelihood that project

development stalls on a section of the grid that is reaching its current hosting capacity as

developers seek to avoid the liability for upgrade costs. Because each project contributes to the 

need for the upgrades, this could represent a fair alternative for allocating costs. Smaller projects 

that are unlikely to trigger upgrades, however, might have an incentive to leave the group and

avoid upgrade costs altogether. Additionally, if a developer withdraws a project, the other 

developers in the group might see costs escalate as they are spread across a smaller group, which 

adds to the potential risk of this approach. This also could result in the need for additional study 

to determine whether the upgrades are still needed, which can delay the process. Also, for the 

transmission cluster study processes in California, there are limited application windows each 

year for a group of projects14 and the review process can take multiple years, which adds to 

project risk and ties up investment capital.

3.2.2 Addressing Repayment Risk

Some cost-allocation policy designs include repayment risk for the PV developer or ratepayers. 

Under the New York PSC interim approach, the developer that pays all initial upgrade costs

assumes the risk of nonreimbursement due to future projects not being developed using the new 

substation capacity. Conversely, under the National Grid demonstration project, ratepayers

assume the risk of the initial upgrade costs not being repaid by future projects. Under the line 

extension model, upgrade costs that are fully covered by a construction allocation are rate based, 

which spreads the repayment burden across ratepayers. For project costs exceeding the 

construction allowance, however, the developer that pays initial upgrade costs assumes the risk 

of nonreimbursement due to future projects not being developed using the upgrade.

 12 Fink, S. et al., “A Survey of Transmission Cost Allocation Methodologies for Regional Transmission 

Organizations,” Exeter Associates, Inc. subcontracted report for NREL, February 2011, 

https://www.nrel.gov/docs/fy11osti/49880.pdf, pg. 3–5. 13 “Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities,” Order No. 

1000, Docket No. RM10-23-000, July 21, 2011, https://www.ferc.gov/whats-new/comm-meet/2011/072111/E-6.pdf, 

pgs. 421–422. 14 There are two distribution group study windows—one in March and one in September. There is only one 

transmission cluster study process window each year.
13

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Under the group cost-allocation approach, upgrade costs are borne entirely by the group and are 

not defrayed by future projects so the main source of risk is from projects dropping out of the 

group and spreading costs over a smaller group of projects15 or triggering the need for restudy, 

which adds time and cost. In an initial filing in MDPU Docket 17-164, distribution companies 

proposed reducing this risk by preventing refunds to projects that drop out of the group (MDPU 

2017). Additionally, making the group study process faster would help reduce the risk that a 

project drops out of a group because, for example, it loses financing. 

3.2.3 Locational Factors in Equitably Allocating Costs Across 

Categories of Projects

If the metrics employed for cost allocation fail to credit the contribution of DER resources both 

behind and in front of the meter, then this will discourage local procurement of DER resources 

whose operating profiles reduce the need for transmission investment. More broadly, generator 

eligibility for ratepayer reimbursement of allocated costs is not equally applied to distributionconnected and transmission-connected resources. It is important to avoid creating inefficient 

market distortions when assigning the delivery costs associated with proximity to load for newly 

interconnected generation.

3.3 Summary and Key Considerations 

The most common approach for upgrade cost responsibility is to assign costs to the project in the 

queue that triggers grid upgrades. Some states and utilities, however, have implemented 

alternative cost-allocation strategies to spread costs across a larger group of projects that benefit 

from upgrades. The key policy-design challenge is to develop a cost-allocation approach that 

fairly allocates upgrade costs through a streamlined mechanism.

• Allocating upgrade costs across a group can decrease the likelihood that project development 

stalls on a feeder where upgrades would be required to accommodate new capacity. 

However, group approaches have challenges in determining how costs are reallocated when a 

project is withdrawn from the group. Another related challenge is designing the mechanism 

so individual projects have no incentive to drop out of the group and reapply for 

interconnection after the upgrades have been funded.

• Utility line extension policy is another approach that is used to allocate costs for new 

infrastructure investments that could potentially serve as a model for treatment of DER and 

assessing costs for current and future customers.

• Equal treatment and cost causation, including credit for avoided costs, are important factors 

to consider in allocation of costs.

 15 This can be counteracted, in part, by requiring developers to pay for upgrades before construction begins.
14

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

4 Interconnection of Standalone Storage and

PV Coupled with Storage

Although energy storage (e.g., batteries) can mitigate the electric system impacts of high 

distributed PV penetrations—depending on how it is deployed—it presents additional 

interconnection issues. Battery storage can act as a load as well as a generator, and its operating 

behavior can be changed relatively easily, making evaluating its grid impacts more complex. 

Additionally, the timing and magnitude of grid exports from storage or PV plus storage systems 

can vary depending on how the storage system is used. Storage can be used for peak load 

shifting, backup power, demand charge reduction, and to enable greater self-consumption 

(minimize grid exports). As storage is increasingly deployed, developing clear methods for 

technical review of an interconnection request will help streamline the interconnection process 

while maintaining system reliability. This section specifically discusses solid-state battery 

storage; however, other electricity storage technologies, including thermal storage systems, could 

also be used in distributed applications. 

4.1 Status and Experience to Date

Many utilities are already interconnecting storage systems, often coupled with PV systems, and a 

few states have addressed the challenges posed by storage and PV plus storage. A basic step is 

clearly stipulating that existing interconnection standards also apply to storage or explicitly 

adding storage under the definition of a generator. States that have taken this step include 

California (PG&E 2017), Colorado, Iowa, North Carolina (Stanfield et al. 2017, 28), and New 

Mexico (New Mexico PRC 2008, 38). FERC Order 792 (2013) also adopted this language for 

the Small Generator Interconnection Procedures (SGIP) for systems up to 20 MW, indicating 

that although the previous definition could be interpreted as including storage, explicitly 

including storage improves SGIP transparency (FERC 2013, 124).

A few states have addressed more complex issues, such as those associated with the load 

attributes of storage and storage control. In the West, two states (California and Nevada) have 

adopted interconnection requirements related to PV plus storage, and three western states 

(California, Nevada, and New Mexico) explicitly incorporate storage into their interconnection 

standards.16 17 Other states that consider storage include Minnesota, New York, Hawaii, Iowa, 

South Carolina, and North Carolina. 

Another key challenge is the differing configurations of PV plus storage (e.g., whether one 

inverter is used or two inverters are used) that affect storage’s ability to discharge to the grid. As 

part of a settlement agreement, Xcel Energy Colorado developed technical guidance documents 

for interconnecting storage alone and PV plus storage, which include recommended system 

configurations represented in single-line diagrams (Xcel Energy 2017a, 2017b, 2017c).

 16 Western state interconnection policies related to storage and PV plus storage are also discussed in the companion 

report, “Review of Interconnection Practices and Costs in the Western States.” 17 A number of states outside of the West explicitly incorporate storage into their interconnection standards, 

including Hawaii, Minnesota, and New York. 
15

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

4.2 Lessons Learned: Design and Implementation Considerations

Additional regulatory guidance could clarify the treatment of battery storage and help 

standardize the approach to interconnecting PV plus storage systems safely and reliably.

4.2.1 Treatment of Storage Load

For a storage project configured to charge from the grid, utilities must evaluate the impact of 

storage load and generation (exports to the grid) on grid safety and reliability. Storage load that 

triggers distribution system upgrades could create ambiguity around how to conduct review and 

how to allocate costs. The California Public Utilities Commission’s (CPUC’s) Decision 16-06-

052, for example, indicates that storage be treated like any other load under the Commission 

Rules (CPUC 2016b, Attachment C, 1). Under California’s Rule 21, upgrade costs triggered by 

storage load are allocated similarly to a line or service extension (PG&E 2017, 15). Nevada’s 

interconnection standards take a similar approach (NV Energy 2018a, 24).

4.2.2 Storage Operation and Control

The flexibility of storage control settings, which can be changed by an owner or operator, can 

complicate technical review of a proposed storage system and pose a regulatory challenge. For 

example, a storage system coupled with PV that has unrestricted charging and discharging 

behavior theoretically could act as a generator at peak capacity simultaneously with PV. If this 

were the case, then a utility would need to evaluate system impact using the aggregate gross 

capacity of PV and storage. However, this could lead to additional review time and system 

upgrade costs that could be avoided if the system was restricted to certain storage operating 

parameters (ESA 2018, vol. 1, 5). Another option for helping influence storage control is to 

encourage grid-friendly operating behavior through tariff design, creating a clear financial 

incentive to charge and generate at certain times of the day (Text Box 1). 

Some states codify that the flexibility of storage can be used to reduce the potential reliability 

impacts of a proposed project on the distribution system and, as a result, their review 

requirements. In California, Rule 21 allows nonexporting standalone storage to be reviewed 

through the expedited fast-track process (PG&E 2017, 240). Additionally, a developer in 

California can specify storage charging behavior in an interconnection application from among 

three modes: no grid charging, peak shaving, and unrestricted charging. For the first two modes, 

charging behavior is restricted and technical review guidelines stipulate that technical review of 

storage load takes these restrictions into account (PG&E 2016). In Nevada, a storage operator 

can propose “optional operating restrictions,” such as a nonexporting configuration, in its 

Text Box 1. Incentivizing Charging Behavior with Tariffs

Hawaii, which has the highest distributed PV energy and capacity penetrations in the country, 

adopted an interim tariff program for PV plus storage to encourage owners to charge their batteries 

during the day and discharge during the evening peak and at night. The Smart Export Program does 

not pay a customer with PV plus storage for exporting power from 9 a.m. to 4 p.m., and it pays the 

customer a fixed amount for power exported during the other 17 hours of the day. Rather than 

stipulating storage control, this program creates a clear economic signal to incentivize certain 

operating behavior for a PV plus storage system. Source: Hawaii PUC (n.d.).
16

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

interconnection application to define certain storage operating parameters (NV Energy 2018a, 

18).

Inadvertent export potentially complicates the technical review of storage. It can occur from 

behind-the-meter storage if there is a sudden decline in onsite load or other rapid changes. A few 

state interconnection standards explicitly address inadvertent export from nonexporting systems

(e.g., California, Hawaii, and Nevada), which recognizes that brief periods of export are 

technically possible for a system that is configured as nonexporting. California and Xcel 

Colorado’s interconnection guidance for storage allow for inadvertent export from nonexporting 

systems, based on clearly stipulated parameters, to help address this issue (ESA 2018, 4; Xcel 

Energy 2017a; PG&E 2017, 234–239). 

On one hand, preventing inadvertent export entirely could significantly restrict nonexporting 

storage operation or require costly protection equipment. However, inadvertent export could lead 

to safety or reliability concerns. For example, if a 20-kW battery system is added to a 20-kW PV 

system (inadvertent export), while the PV is at maximum generation—even for a few seconds—

it could come very close to the 200-amp rating of the main breaker on the service panel and the 

200-amp service rating of the utility service to the location. If two 20-kW batteries were installed 

with a 20-kW PV system, inadvertent export from both systems would be well beyond a 200-

amp service. Ongoing work and state proceedings are still grappling with how to technically 

screen inadvertent export-only systems. No clear best practice has emerged outside of the fact 

that it is an issue that must be addressed.

4.2.3 Treatment of Combined PV and Storage Capacity for 

Interconnection Review

Setting storage operating behavior using system controls could potentially lower the net capacity 

of PV plus storage, which could help reduce technical review requirements and reliability 

impacts of a proposed system. For example, as with the operating modes used in California to 

define storage charging behavior (Section 4.2.2), a storage system could be programmed to 

generate during the late-afternoon peak, after the PV system’s output has declined. Currently, 

only a few western states have incorporated this net-system-capacity approach into 

interconnection requirements, and the extent to which these alter the review process is still under 

consideration (ESA 2018). Concerns have been noted with several electric utilities that energy 

storage systems could inadvertently export to the grid during the same hours that PV systems are 

generating and exporting, potentially exacerbating technical issues such as voltage control and 

power flow.

18 DER systems that contain a PV system from Manufacturer A and a battery storage 

system from Manufacturer B could especially be prone to operational conflicts, as nonintegrated 

systems have a greater likelihood of creating unwanted grid impacts, especially when the

systems are installed by separate companies. 

As part of Xcel Colorado’s storage interconnection guidance documents adopted in a settlement 

agreement, the net capacity of a PV plus storage system used to evaluate potential system 

impacts can be reduced from the aggregate capacity of the two systems if it “is limited by 

programming or by some other on-site limiting element” (Xcel Energy 2017a, 2). Nevada’s 

interconnection standards explicitly define a generator’s “net nameplate rating” as the capacity of 

 18 Taken from NREL notes with utilities in Minnesota, Arizona, and California. 
17

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

a system that is limited by “use of a control system, power relay(s), or other similar device 

settings or adjustments” (NV Energy 2018a, 4). Additionally, in Order 792 (2013), FERC 

adopted language into the SGIP that allows a “control system” to be used to reduce the system’s 

net capacity (FERC 2013, 195). However, there are currently ongoing discussions in state 

proceedings regarding to what extent the net capacity of PV plus storage actually changes the 

need for technical review relative to looking at the nameplate ratings of the systems. One 

concern is that it is very easy for a customer to change storage operating behavior through a 

software update. If market tariff structures change, there could be a strong financial incentive for 

customers to change how their storage systems are operating. If technical review only evaluates 

the net capacity of a system under restrictive operating parameters, then this change in operations 

could have an adverse impact on the system. Because conversations regarding the net capacity 

approach are ongoing, no clear best practice has emerged yet.

The IEEE has approved a Project Authorization Request, IEEE P1547.9, Guide to Using IEEE 

Standard 1547 for Interconnection of Energy Storage Distributed Energy Resources with 

Electric Power Systems,

19 that might help answer some of these concerns and other potential 

challenges that lie ahead. The guide will help develop solutions to grid-tied DER systems, such 

as PV and storage, as well as nonexporting energy storage systems, including uninterruptible 

power supply systems or electric vehicle (EV) chargers. Development of this standard is 

scheduled to begin in early 2019 when a working group will convene and begin work on the 

document. 

4.2.4 Net-Metering Compensation

In a state where PV receives NEM compensation, a mechanism might be needed to ensure that 

PV plus storage customers only receive the NEM rate for renewable generation and not for any 

energy that was charged from the grid. One option is simply to prohibit the storage system from 

exporting power. Another option is to require separate metering of PV and storage, which could 

add significant costs for wiring and metering, particularly for small DER systems. Additionally, 

the difficulty in metering systems can also depend on the system configuration.20 A third option 

is to estimate PV output, crediting a PV plus storage owner for the estimated PV production each 

month. California, Colorado, and Nevada demonstrate use of these options.

• California has different requirements to validate NEM generation paired with storage, 

depending on storage system size. Storage systems larger than 10 kW and coupled with an

NEM generator must be metered separately. Storage systems that are 10 kW and smaller 

connected alongside PV can be compensated using an “estimation methodology” that caps a 

generator’s NEM compensation based on a projected monthly output profile for a PV system

(CPUC 2016a, 38–40). The estimation methodology reduces customer installation costs for 

smaller storage systems because it avoids the need for costly metering equipment.

• As stipulated in a 2016 settlement agreement (Colorado PUC 2016), Xcel Colorado provides 

NEM compensation for a DER plus storage system only when the storage is charged by the 

 19 See IEEE Standards Association page at https://standards.ieee.org/project/1547_9.html. 20 The complexity of metering PV plus storage depends on whether it is an AC- or DC-coupled system. For 

additional information on this issue, see the NREL reports, “Evaluating the Technical and Economic Performance of 

PV Plus Storage Power Plants,” and “Xcel Energy Guidelines for Interconnection of Electric Energy Storage with 

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

NEM generator alone; thus, the generator cannot export power if the storage system charges 

from the grid (Colorado PUC 2017, 175). Although this approach requires more metering 

equipment than the estimation methodology designated for smaller storage systems in 

California, it provides precise accounting of NEM generation. However, Colorado Senate 

Bill 18-009, passed in March 2018, stipulates that the utility cannot require an additional

meter to be installed to meter a storage system alongside an NEM generator (Colorado 

General Assembly 2018). 

• Nevada’s interconnection standards require one of two operating restrictions on storage 

systems paired with an NEM generator. One operating restriction is that the storage system 

cannot export power. The alternative restriction is that the storage system can only be 

charged by the NEM generator (NV Energy 2018a, 18). 

4.2.5 Storage Metering

Directly metering behind-the-meter storage systems can give a utility additional insight into how 

storage systems are operating. For example, the Nevada Commission Order and settlement 

agreement incorporating storage into its interconnection standards stipulates that revenue-grade 

utility meters will be installed on new storage systems. According to the utility NV Energy, data 

from storage meters could be used to develop future tariffs for storage or to inform distribution 

system planning (NV Energy 2018b, Attachment 1). However, this can add cost to a storage 

system if the developer is charged for the additional meter, as stipulated in the Nevada 

Commission Order. Also, as agreed to in the settlement agreement, NV Energy will collect thirdparty inverter data and evaluate whether those data can be used as a lower-cost alternative to 

direct utility metering (Ibid. 4–6). Additionally, allowing the utility to directly meter the storage 

system behind the utility meter could raise privacy concerns.

4.3 Summary and Key Considerations

As more PV plus storage systems are proposed, a number of questions are arising about the 

process of interconnecting these systems. Issues include the following:

• Clarifying the application of existing interconnection standards to storage.

21

• Clarifying the treatment of storage as load and addressing issues such as how costs are 

allocated if storage load triggers system upgrades.

• Determining the net capacity of storage coupled with PV for purposes of establishing the 

threshold for interconnection review could consider storage operating behaviors.

• Developing a method to ensure that a PV plus storage system only receives NEM credit for 

PV-generated electricity exported to the grid.

• Outside of the interconnection process, rate design could be used to incentivize desirable 

storage charging and discharging behavior. This behavior could include charging from the 

grid during off-peak hours and exporting to the grid during peak hours.

 21 IEEE 1547-2018 and UL 1741/UL 1741SA apply to storage inverters. The updated standard—IEEE P1547.9—

directly focuses on how to design the behavior of energy storage systems—both exporting and nonexporting. 
19

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

5 Hosting Capacity

A utility must ensure that interconnecting PV to a distribution system does not negatively impact 

electric power quality or reliability for customers. For example, a newly interconnected 

distributed resource cannot cause voltage deviations in general, over-voltage deviations in 

particular, unintentional islanding, or violations of thermal and protection limits. Hosting 

capacity refers to the aggregate PV (and other DER) generation capacity that can be 

interconnected to a distribution system without requiring system-infrastructure upgrades. Hosting 

capacity can be reported at various spatial levels (e.g., substation, feeder, and local nodal 

levels22), and can include either a specific limit or a range that depends on either existing or 

anticipated grid conditions and operations, along with the type, size, and location of DERs. 

Often, for example, the maximum hosting capacity for customer-sited generation is in the section 

of a radial feeder closest to a substation, and the minimum value is in the feeder section furthest 

from a substation. Although distributed PV is the primary focus of current hosting-capacity 

analysis (HCA) because of its comparatively high penetration, HCA also can evaluate the ability 

to host other technologies such as distributed storage and electric vehicles.

5.1 Status and Experience to Date

Although, in the past, utilities often relied on estimates in considering interconnection requests, 

rapid growth in DER interconnection requests and the recognition that there is a need to 

proactively plan for integration of DERs have prompted some jurisdictions to explore new 

methods for determining hosting capacity more accurately.

5.1.1 Screening Approaches

Some utilities use fast-track screening in processing interconnection requests. These approximate

a more technical assessment of hosting capacity, but only if a DER is unlikely to trigger 

violations of voltage, thermal, or protection limits. Supplementary studies of DER 

interconnection impacts typically are required when a fast-track screening is not passed. 

Interconnection of low-impact electric power generation—such as distributed PV in an area with 

low DER penetration—usually is expedited. Low penetration for technical screening frequently 

has been defined as a distribution feeder or feeder line section with an aggregate DER capacity 

of less than 15% of annual peak load (Coddington et al. 2012, 2; FERC 2013, 70–85).

The so-called 15% screen is a capacity-penetration measure derived from an approximation used 

by distribution-planning engineers. It is based on the observation that typical residential

distribution feeders have minimum daily loads of approximately 30% of their annual peak loads.

Thus, the 15% screen is relatively conservative (Coddington et al. 2012, 2). Consequently, 

certain entities (e.g., the CPUC) use supplementary screening for interconnection applications 

that fail an initial 15% screen, allowing DER penetration of up to 100% of actual or estimated 

coincident minimum daily load (i.e., 30% of annual peak load during operating hours, as in the 

previous assumption). Small DER projects, such as residential PV, often pass this supplementary 

screen even if they fail an initial 15% screen. A distribution circuit with aggregate PV capacity 

 22 Substation refers to the infrastructure (e.g., stepdown transformer) at the interface between subtransmission and 

the distribution system. A primary feeder exits a substation and can serve various customer types. Secondary 

feeders—usually located after a subsequent stepdown transformer—directly serve commercial, industrial, or 

residential customers. Nodes are locations along a feeder. 
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of more than 100% of minimum daytime load would export power to the substation bus, which is 

not necessarily a problem.

In any case, such rule-of-thumb screens fail to account for the heterogeneity of hosting capacity. 

Determinants of hosting capacity include DER location on the feeder, feeder topology, design 

and operation, and DER technology (EPRI 2016, 3). Of these factors, DER location and 

operating profile are most important. The other factors also can influence the ability to assess 

hosting capacity accurately using screens. For instance, voltage class and load location are 

particularly important influences on feeder topology, design, and operation. Negative impacts 

could be mitigated by using one or more advanced-inverter function in conjunction with DER 

technology. Advanced inverters can, for example, provide reactive power support, thereby 

reducing the distribution system impacts of PV generation (McAllister 2016, 11). These factors 

yield DER hosting capacities that can vary considerably and differ from 15% of annual peak 

load. Therefore, some jurisdictions have undertaken efforts to develop more detailed locationspecific HCA.

5.1.2 California Investor-Owned Utility Hosting-Capacity Analysis and Map

California IOUs have developed a feeder-specific analysis of hosting capacity to assist with 

distribution system planning, expedite interconnection request processing, and provide 

information about grid conditions for developers planning projects. California created a 

multistakeholder Integration Capacity Analysis (ICA) Working Group in May 2016 to guide 

development of HCA methods.

23 The ICA effort is part of a broader effort launched by the 

CPUC to improve distribution resource planning (DRP) that includes identifying “optimal 

locations for the deployment of distributed resources” (CPUC n.d.). In evaluating locationspecific benefits and costs of DERs, IOUs must consider criteria such as reductions (or 

increases) in local generation capacity needs and reductions (or increases) in investments in 

distribution infrastructure (CPUC n.d.). Investor-owned utilities are required to minimize 

investment in the grid and simultaneously add DERs to reduce greenhouse gas emissions.

Results of an ICA—which is synonymous with HCA—are made publicly available (usually upon 

filing a request with the utility) in online maps. Figure 1 is a portion of a map developed by 

Southern California Edison (SCE) for its ICA (SCE n.d.a.). ICA goes beyond PV capacity 

analysis to accommodate all DERs including other inverter-based generation, energy efficiency, 

demand response, energy storage, and electric vehicles. These items currently are represented in 

data sets as “load capacity” and “generation capacity,” with specific values for PV. The maps 

include results of demonstration projects as well as expanded ICA results territory-wide, updated 

monthly (PG&E n.d.; SDG&E n.d.; ArcGIS. n.d.). Data for each feeder include existing 

generation (MW), queued generation (MW), maximum remaining generation capacity (MW), 

15% penetration capacity (MW), current penetration level (%), projected load (MW), integration 

capacity of generation (MW), and integration capacity of load (MW) (SCE n.d.). Certain data 

useful for developers (e.g., feeder voltage) have been available in California prior to initiation of 

ICA; other states could consider making such data publicly available as a preliminary step 

toward HCA. Additionally, although hosting-capacity maps are public summaries of HCA, the 

underlying data also are important. As an example, load curves for various criteria (e.g., thermal) 

 23 ICA/LNBA Working Group materials are available at https://drwg.org/sample-page/drp/.
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This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

are of great value to developers in ascertaining whether infrastructure upgrades will be required 

for a DER project as well as upgrade costs.

Figure 1. Portion of SCE service territory with hosting-capacity results, 

from publicly available DRP map

Note: Hosting-capacity map from portion of SCE service territory. Blue squares represent distribution substations.

Color-coding of available hosting capacity is: orange, 0.0 through 0.3 MW; shades of green, 0.4 through 3.0 MW.

Map is best viewed at 200% within document.

The ICA Working Group’s final report identifies transparent and automated interconnection 

request processing as the primary use of ICA, with a secondary goal of informing distribution 

planning to better integrate DERs (ICA-WG 2018). PG&E, SDG&E, and SCE conducted two 

pilot studies each across rural and urban feeders to determine the most accurate and applicable 

ICA method. Importantly, the Working Group concluded that the so-called iterative method for 

ICA is preferable to the streamlined method for the interconnection use case; a streamlined or 

hybrid approach might be appropriate for other use cases in which precision is less important 

than the ability to compare multiple scenarios. The streamlined method uses sets of equations 

and algorithms along with numerous criteria (e.g., voltage limits) to determine hosting capacity 

at each distribution system node. The iterative method performs power-flow simulations while 

increasing aggregate DER capacity (in 500-kW increments) at each distribution node until a 

power-quality criterion is violated. Although the iterative approach is more computationally 

intensive, most of the Working Group favored it because it is more robust for evaluating 

interconnection applications in the future (California Distribution Resources Plan (R.14-08-013) 

Integration Capacity Analysis Working Group 2016).
22

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

5.1.3 Hosting-Capacity Analysis and Mapping in Other States

In Hawaii, the Hawaiian Electric Company (HECO) has taken an iterative approach to analyze

all system feeders and make hosting-capacity data available via maps updated each weekday

(HECO n.d.). Currently, data available by feeder include availability as a percentage and in kW 

capacity, along with the penetration range by circuit peak load (%). The data are helpful for

identifying interconnection red zones (those with less than 5% availability) that would likely 

require costly upgrades to accommodate additional PV generation. However, HECO states that 

the data only represent the primary distribution network and that more information about the 

secondary network is needed to determine firmly whether an interconnection study is necessary. 

Although an explicit primary hosting-capacity use case has not been stated, Hawaii’s Public 

Utilities Commission set grid-modernization goals to automate system control and operation, as 

well as to allow for greater penetration of DERs (Hawaii PUC 2018), which loosely fall into 

interconnection and distribution planning use cases, respectively. These use cases resemble those 

for California.

New York Joint Utilities has undertaken HCA as part of its Distributed System Implementation 

Plans. Although it has not explicitly stated a principal use case, it has outlined a four-stage HCA 

implementation (Joint Utilities of New York 2016):

1. Distribution indicators

2. Hosting-capacity evaluations

3. Advanced hosting-capacity evaluations 

4. Fully integrated DER value assessments.

During the first stage, the Joint Utilities collected data at the feeder level. New York IOUs made 

publicly available hosting-capacity maps for all 12-kV (and greater) feeders in late 2017.24 For 

stage two, initial maps generated using the Electric Power Research Institute’s (EPRI’s) DRIVE 

tool indicated red zones to avoid for large (greater than 300 kW) PV systems owing to the likely 

need for costly upgrades. Currently, data available in map and tabular form for each feeder 

include the annual peak load (MW), whether an interconnection study has been completed or is 

needed (yes/no), minimum and maximum PV hosting capacity (MW), and installed and queued 

generation (MW). Data only are available for total DG (not in generation-technology-specific 

format) hosting capacity thus far, and they are updated on an annual basis (with queued and 

current-generation values updated monthly). In stage three, utilities aim to include subfeederlevel hosting capacity as well as current and prospective DERs to model the distribution system

more accurately. Hosting-capacity results from this stage will be very useful in that they will 

provide a narrower range of hosting capacities than that currently provided (often a kW to MW 

range), thereby enhancing usefulness to stakeholders.

Xcel in Minnesota has similarly used EPRI’s DRIVE tool to model large and small DG on many 

of its feeders (ICF International 2016). Current data provided on the map are similar to data for 

the New York utilities, with an additional column indicating “mitigation required to 

 24 Hosting-capacity maps for New York IOUs are available at http://jointutilitiesofny.org/utility-specificpages/hosting-capacity/.
23

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accommodate proposed DG,” which could suggest moves toward using HCA for distribution 

grid planning (Xcel Energy n.d.).

5.2 Lessons Learned: Design and Implementation Considerations 

Although HCA is in its nascent stage, participating states and utilities offer various lessons 

learned in navigating challenges associated with designing and implementing these analyses. The 

Interstate Renewable Energy Council (IREC) outlined several HCA best practices: Ensuring an 

inclusive and fair stakeholder process from the beginning, defining and selecting use cases for 

HCA that can apply to a range of DERs before identifying proper implementation criteria and 

methods, ensuring model validation and transparency, and providing consistency across regions 

(IREC 2017). Additional lessons are discussed below.

5.2.1 Intended Uses

The intended use is important for determining the level of accuracy required, so it should be 

considered at the outset. Hosting-capacity analysis can be used for several different purposes, 

including streamlining interconnection, providing information to developers about grid 

conditions, and conducting distribution system planning in a more holistic manner (ICF 2016; 

IREC 2017). Using HCA data to streamline the interconnection process and automate 

screening—as is done in California—requires accurate estimates. It also requires frequent data 

updates.

If hosting-capacity data are used to inform customers about where it might be best to install 

projects to avoid potential grid upgrades, there is a somewhat lesser need for highly accurate data

than for processing interconnection requests. Hosting-capacity data can be used to provide 

guidance about the relative ease of interconnecting in particular locations through highlighting 

restricted areas or areas with minimal concerns (e.g., identifying red, yellow, and green areas). 

Alternatively, analysis could focus only on specific feeders of concern or grid hotspots, which 

could be sufficient to satisfy needs in some jurisdictions. Using HCA for distribution system 

planning might be able to employ less-precise estimates of hosting capacity.

5.2.2 Methods and Data Accuracy

Methods for HCA are still emerging, with several levels of sophistication being used in various 

jurisdictions. Methods include detailed iterative power flow analysis, approaches based on 

algorithms, and spreadsheet-based models that attempt to determine when violations of powerquality criteria would be triggered. The data needs and processing time (and associated expense) 

can vary substantially across approaches. Although it is generally uncontroversial that capacity 

penetration measures must be supplanted by more precise measures, the specific approach to 

HCA is more controversial because of considerations such as use case involved and costs 

incurred.

The selection of method depends not only on the intended use(s) of the analysis, but also on the 

current and expected penetration of DERs in the area. The ICA Working Group in California 

concluded that an iterative method is preferable to a more streamlined method for expediting 

interconnection despite its time-intensive nature (and associated expense). The iterative method,

however, might not be feasible for smaller utilities or might not be desirable for locations with 

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

The most effective methods might not be the same for different uses. For example, California 

utilities have decided that the iterative HCA used for fast-tracking interconnections might not be 

suitable for distribution planning owing to its computational intensity and lesser ability to handle 

multiple future scenarios which, in California’s case, would represent business-as-usual, high 

DER growth, and very high DER growth (ICA-WG 2018).

Model validation and method transparency are also important. California utilities, through their 

first set of HCA demonstration projects, ran their respective models across urban and rural 

feeders in addition to a test feeder to determine which method (e.g., iterative versus streamlined) 

generated the most consistency. In testing separate method variations, utilities were able to 

justify a final method that proved to be the most consistent.

5.2.3 Frequency of Updates and Public Accessibility of Information

Frequency of data updates is driven by the use case and the growth trajectory of DER in a region. 

Less frequent updates might be sufficient if the primary purpose of HCA is distribution planning. 

Although many jurisdictions have developed maps based on HCA, there might be concerns about 

making sensitive data on grid conditions publicly available. One method of addressing this 

concern is to restrict map and data access to customers with an account in the utility service 

territory. This method is, however, an imperfect solution to securing sensitive data. An approach 

used by a Minnesota utility, Xcel Energy, is to aggregate data visually. Instead of illustrating 

individual feeders and data for each feeder, Minnesota hosting-capacity maps aggregate feeders 

into zones with ranges of hosting capacity. This approach represents a securing of distribution 

infrastructure information. 

5.2.4 Cost Considerations

The analytic method used has significant implications for the cost of HCA and mapping. There 

can be substantial differences in cost and data requirements for running power-flow simulations 

for all feeders on an hourly basis versus methods that involve simplified estimation of levels that 

would violate power system limits. Potential cost savings achievable through the process 

nonetheless could warrant more data-intensive approaches; for example, if the data are used to 

automate the interconnection process, staff time could be saved. Potential savings are not certain 

at the outset, however, and can depend on the magnitude of expected installations of DERs in the 

region in subsequent years. Some utilities might not be able to employ a relatively time-intensive 

and expensive methodology for determining hosting capacity or might not need such an 

analytically rigorous approach. Alternatively, new computing approaches (such as cloud 

computing) could reduce or even eliminate these cost concerns.

The frequency of updating publicly available hosting-capacity data is another significant cost 

consideration. HECO updates maps each weekday, California updates maps each month, and 

New York and Minnesota do so each year. The growth in DER and the magnitude of grid 

challenges are important considerations for determining the appropriate frequency of updates

because high DER growth or challenging grid conditions obligate more frequent updating.

5.3 Summary and Key Considerations 

Various jurisdictions have estimated hosting capacity with methods beyond simple capacitypenetration measures. Hosting-capacity determination by detailed, feeder-specific assessments 
25

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

can provide more accurate estimates of DER capacity that can be accommodated on the grid. A 

range of analytic approaches exists, and methods continue to evolve.

• The level of analytic rigor needed can vary depending on the use case. For example, methods 

that are best for planning could differ from those that are useful for streamlining 

interconnection. Regarding the latter, areas with high numbers of interconnection requests

would benefit from more rigorous hosting-capacity determination or use of advanced 

inverters.

• The current and expected level of DER penetration is important for determining appropriate 

approaches to hosting-capacity analysis. Jurisdictions might benefit from improving hostingcapacity determination prior to anticipated increases in interconnection requests.

• Making hosting-capacity data publicly available can help developers deploy DERs at 

locations in distribution systems with available hosting capacity, thereby avoiding costly 

detailed studies for interconnection requests and reducing utility resource use in conducting 

such studies. However, there can be concerns about making data about grid-related issues 

publicly available.
26

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

6 Locational Value

Locational value is emerging as an important consideration as DER penetration increases. In the 

western United States, current DER generation is relatively low. Only in Arizona and California 

are retail sales of distributed PV generation greater than 1% of total sales (EIA 2018a, 2018b). 

This proportion, however, is projected to grow to 5% to 10% in certain western states by 2026 

(WECC 2016, 12–16).

Locational DER value is important because, if strategically located, DERs can defer grid 

upgrades at the distribution and transmission levels. Conversely, undesirable impacts—such as 

voltage abnormalities—can occur as cumulative DER capacity increases on a distribution feeder. 

Thus, locating DERs to maximize grid-deferral value and avoid undesirable impacts is optimal.

6.1 Status and Experience to Date

Although DERs only recently have made significant contributions to the grid, and their location 

generally has been given little consideration, some states are beginning to analyze it. 

California—where DER deployment has accelerated recently—has ongoing proceedings in 

which hosting capacity and deferral value of DERs are being considered. New York, which has

less DER deployment than California, is more proactively considering DERs with respect to their 

deferral value. Although other states (e.g., Hawaii, Massachusetts, Minnesota) are addressing 

DERs and related issues, California and New York are leading in the consideration of locational 

value.

6.1.1 California’s Use of Locational Value

Locational net benefit analysis (LNBA) refers to determining the net benefit of DERs at a given 

location within a distribution system. Costs of any distribution system infrastructure upgrades 

necessary for DER interconnection (e.g., those needed to prevent abnormal voltage deviations) 

are considered. Thus, optimal locations for DERs include consideration of hosting capacities and 

locations where benefits exceed costs.

California’s LNBA Working Group, established in May 2016, guides utility analysis of 

distribution investment deferral value and locational avoided costs (CPUC n.d.). It has guided the 

analysis methods and the IOUs’ Demonstration B Projects used to evaluate locational value of

DERs.25 Under Demonstration Project B, the utilities were required to identify gridinfrastructure projects that could be deferred with the use of DERs and to calculate LNBA under 

different DER growth scenarios. The IOUs examined near-term (1 to 3 years) and longer-term (3 

years or more) distribution-system infrastructure projects that could be deferred.

As part of the Demonstration Project B effort, the IOUs calculated LNBA using the CPUCapproved DER Avoided Cost (DERAC) Model that was developed by the consultancy Energy 

and Environmental Economics (E3 n.d.). This model determines time- and location-specific 

avoided costs due to energy efficiency, DG, and demand-response programs. DERAC was 

supplemented with various enhancements that included location-specific values for certain 

variables (e.g., generation energy, replaced by locational marginal pricing) as well as a list of 

 25 The utility Demonstration Project B and Project C specifically relate to locational benefits. Other demonstration 

projects have been developed to analyze other aspects of DER integration, such as hosting capacity, high 

penetrations, and using DERs for reliability. 
27

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

value components. These enhancements and value components reflect, for example, the benefit 

of DERs reducing net-loading impacts on distribution infrastructure. The value categories 

specified in the CPUC guidance included distribution project deferral (substation/feeder, 

voltage/power quality), distribution reliability and resilience, transmission project deferral or 

avoided cost, avoided renewable energy integration costs, resource adequacy, avoided ancillary 

services, and avoided societal and safety costs (CPUC 2016c). 

As part of Demonstration Project B, LNBA was used to calculate the avoided costs and deferral 

values for each of the projects. Using the results, the utilities produced maps that identified 

potential project deferrals. A sample outcome of Demonstration Project B, a publicly available 

LNBA map by SDG&E, is displayed in Figure 2. Through this process, PG&E identified 10 

potential deferral projects, SCE identified five projects, and SDG&E identified four projects. 

Demonstration Project B analysis was completed in December 2016 (Scott Madden 2017). The 

Working Group’s final report on long-term refinements to the LNBA process was issued in 

January 2018; the report provides detailed discussion of potential improvements to the locational 

valuation methods and identifies a path forward (CPUC n.d.).

Figure 2. Portion of SDG&E service territory from publicly available LNBA map26

SDG&E n.d.b. Orange-enclosed LNBA project area (voltage regulator required to mitigate low-voltage issue) has 

modest DER deferral value ($$). Green-enclosed LNBA project area (mitigation of overloading on feeders 596 and 

597 required) has greater DER deferral value ($$$).

 26 LNBA maps are available from SDG&E (n.d.b). To access a map, scroll to Interconnection Map V17 and click 

the link to open it. A username and password are required to access LNBA maps (last visited December 7, 2017).
28

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

In February 2017, the CPUC approved Demonstration Project C proposals for all IOUs (CPUC 

2017a), which are field demonstrations to assess the ability of DERs to achieve net locational 

benefits for at least three benefits categories examined using the LNBA method. The objective of 

these demonstration projects is to validate the LNBA method and determine whether DERs can 

defer infrastructure investments and meet local capacity and energy needs (Scott Madden 2017). 

For example, SCE plans to install DERs (such as distributed PV generation and battery storage) 

to test whether they can defer traditional infrastructure projects (e.g., new distribution circuits) 

and provide other grid services. SCE plans to finalize the project and issue results by the end of 

2019 (SCE n.d.b).

Eventually, the CPUC could expand the use of LNBA to influence siting and deployment. A 

CPUC staff memo on potential use cases for LBNA discusses the potential for incorporating 

locational value in future tariffs and incentives, such as NEM, resource evaluation, and 

potentially integrated resource planning (CPUC 2017b).

6.1.2 Assessment of DER Deferral Value in California

Although deferral value is a key component of the locational value of DERs, recent research 

conducted by the University of California at Berkeley for one California IOU’s territory suggests

that a limited number of locations have potential for deferral (Cohen et al. 2016). The 

investigators simulated eight representative feeders for two California locations—Berkeley and 

Sacramento. Distribution system data from the IOU serving these two locations, PG&E, also 

were used.

The study showed an average distribution system infrastructure project deferral value of 

approximately $6/kW-year across all feeders in the PG&E territory, which is very low relative to 

the cost of distributed PV generation (Cohen et al. 2016, 145, 148). Approximately 10% of all 

feeders required infrastructure projects within 10 years, however, yielding infrastructure deferral 

values of greater than $10/kW-year; in turn, 10% of that subset of feeders had deferral values of 

greater than $60/kW-year. The investigators suggested that compensation for distributed PV’s 

locational value could be an effective strategy for incenting DER deployment within the small 

subset of distribution system feeders with relatively high deferral value. Importantly, this subset 

of feeders might be very small, as suggested by the study finding that just 1% of all feeders in the 

PG&E distribution system have a relatively large infrastructure deferral value of more than 

$60/kW-year (Cohen et al. 2016).

It is important to note, however, that distribution system infrastructure investment is only one 

potential component of deferral opportunity and value. DERs also can defer transmission 

investment and replace conventional generation. LNBA calculates the stacked value of multiple 

such values, adjusting for local conditions. Conventional generation includes both spinning 

reserves and so-called peaking facilities, the latter typically operated at low capacity factors.

In 2017, more than $2 billion in planned transmission costs were avoided in California with the 

deferral or cancellation of several projects. Deferral or cancellation resulted from changes in 
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local load forecasts due to energy efficiency programs and the increasing deployment of 

distributed PV generation.27

6.1.3 New York’s Use of Locational Value

New York’s Reforming the Energy Vision (REV) strategies include increasing DER deployment 

to achieve goals of reducing greenhouse gas emissions by 40% and reaching 50% renewable 

electricity generation by 2030 (NY DPS 2016, 1). Distributed PV generation is projected to 

contribute approximately 3,600 GWh of renewable generation annually by 2023 (NY PSC 

2016a).

In late 2015, the New York PSC issued a notice requesting comments and proposals on an 

interim successor to New York’s NEM scheme and locational value of DERs (NY PSC 2015, 2).

After several rounds of comments by a variety of stakeholders and a preliminary proposal for a 

successor to retail rate NEM compensation by the PSC, an order was issued by the PSC detailing 

the successor in early 2017 (NY PSC 2016c; NY PSC 2017d). A subsequent order, issued later in 

2017, provided calculations for determining locational value of DERs (NY PSC 2017c, 10–16).

In the 2017 orders, retail rate NEM compensation was to be replaced immediately by one of two 

value of DER tariffs—a Phase 1 NEM tariff (identical to retail rate NEM, but only available for 

90 days after issuance of the order) or a Phase 1 Value Stack tariff (NY PSC 2017d, 122–130). 

Various DER project types were eligible for these tariffs, including mass-market projects (e.g., 

residential and commercial PV systems), community DG, remote net-metered projects, and 

onsite large DER projects. Although mass-market projects were expected to opt for the Phase 1 

NEM tariff, such projects might benefit from opting into the Value Stack tariff (NY PSC 2017d, 

122).

Compensation for net-metered, DER-generated power depends on the order in which DER 

projects appear in the interconnection queue. Groupings of projects (termed tranches) are 

compensated differently. Tranche 0 projects are compensated at the Phase 1 NEM tariff rate, 

Tranche 1 at the Phase 1 Value Stack tariff rate (Tranches 0 and 1 are combined into one tranche, 

termed Tranche 0/1), and Tranches 2 and 3 at progressively lower rates than the full Value Stack 

tariff rate (NY PSC 2017d, 122–130).28 Aggregate generation capacity in each tranche for a 

given IOU cannot exceed that which is projected to reduce IOU revenue by more than 2%. 

The Value Stack tariff—meant to improve upon retail-rate NEM compensation by providing a 

full and accurate value of DER—is determined by several factors, including energy value, 

capacity value, environmental value, demand reduction value (DRV), and locational system 

relief value (LSRV). The DRV and the LSRV are measures of DER locational value. The LSRV 

in particular provides a very specific measure of a given DER project’s ability to meet a utility 

need (e.g., to defer infrastructure investment), and is determined by project location and other 

 27 An example of potential deferral or cancellation in California is the Oakland Reliability Proposal for PG&E 

service territory. In this proposal, energy efficiency, demand response, DG, and storage serve as alternatives to an 

aging conventional generator or a new transmission line. PG&E analysis of this proposal demonstrates multimilliondollar savings for ratepayers. There are similar examples elsewhere in the state. 28 For example, ConEd has aggregate DER capacities of 137, 206, and 205 MW in Tranches 0/1, 2, and 3, 

respectively; revenue reduction across tranches is projected to be $43.5 million, which is 1.72% of revenue (NY 

PSC 2017d, 131–132).
30

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characteristics (NY PSC 2017d, 94–119). Figure 3 shows an LSRV area map submitted to the 

New York PSC by the IOU ConEd. 

The tariff is still being refined and debated. A July 26, 2018, PSC staff paper (NY DPS 2018) 

proposed to sunset the LSRV tariff because of the difficulties in designing a stable and effective 

tariff that compensates for locational benefits. Staff argued that the distribution system planning 

process and nonwires alternatives (NWA) approaches might be more effective at compensating 

for targeted projects that provide locational benefits than the tariff. The LSRV tariff design might

not provide sufficient certainty to developers to incentivize deployment in preferred locations.

This is true because projects need to operate during the top-10 peak hours, which are unknown

until after the fact. Another issue that has been raised is that the values could change 

dramatically once NWA projects are completed to address problem areas. At the time of this 

writing, staff are seeking comments on the proposal and it is uncertain how the tariff will be 

revised. 

Figure 3. Example of LSRV-eligible area map of IOU ConEd for Borough of Brooklyn 

Note: Green areas are LSRV-eligible. The Borough Hall network (northwestern corner of map) offers the possibility of 

subtransmission infrastructure investment deferral by DERs. The DER capacity cap for Borough Hall is 14.3 MW 

(NYSERDA n.d.).

6.2 Lessons Learned: Design and Implementation Considerations

6.2.1 Defining Objectives of Locational Value Analysis

Jurisdictions can have a variety of objectives in undertaking locational value analysis for DERs. 

Clearly defining those objectives up front through a stakeholder process can yield the most 

effective results. Objectives might include understanding where DERs can defer grid upgrades to 

save on infrastructure costs, using the data to inform ongoing distribution-system planning 

processes and investment decisions, and designing tariffs and incentive programs to encourage 

deployment of DERs in preferred locations. To date, the California approach has focused on the 

first objective, although the CPUC has indicated interest in incorporating locational value in 

future iterations of NEM. New York is incorporating locational benefits of DERs into its NEM 

tariff structure and is evolving the tariff over time.
31

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6.2.2 Methods for Assessing Locational Values

Quantification of locational value is in its infancy. The California LNBA Working Group and the 

New York IOUs have developed demonstration projects and preliminary methods, respectively, 

but these methods continue to evolve. Quantification is more refined and widely accepted for 

some categories of benefits than for others; therefore, the scope of the benefit categories 

examined influences the methodological challenges. California recently issued a report with 

potential long-term improvements to the methods used to calculate LNBA and it plans to address 

those improvements. The intended use of the analysis will drive the analytical rigor of the 

methods.

6.2.3 Categories of Locational Benefits

Locational value determination can cover a variety of benefits at the bulk power and distribution 

system levels as well as societal benefits. Hosting capacity and infrastructure project-deferral 

value are accepted as key components of locational value, but there could be reasons to address 

other benefit categories depending on the use case. Including specific categories of benefits can 

be subject to controversy and methods for assessing some categories are more developed than 

others. California has approached the issue by examining an expansive list of benefit categories

that could be selected as appropriate, including societal benefits. New York, conversely, has 

focused on peak load relief (i.e., LSRV) and locational marginal pricing. Costs of determining 

locational value will necessarily vary according to the range of categories considered. If, for 

example, only a planned distribution infrastructure project deferral value is considered, then 

costs could be relatively low as compared with analysis of a broader range of categories. 

Considering additional factors increases the costs and the resources needed for determining 

locational value; the primary-use cases influence the range of categories to evaluate.

6.2.4 Using Locational Value to Drive DER Investments

There are several approaches for using analysis of DER locational value to drive the market for 

DERs. Approaches include modifying tariffs or incentives to send price signals that capture 

locational value, incorporating locational criteria in procurements of new DER capacity, and 

developing programs that target DER deployment in specific locations. Examples of programs 

include deploying community solar projects in preferred grid locations or developing community

challenges and targeted marketing campaigns in areas where increased DER could have value. 

New York already has incorporated locational elements in its tariff; other jurisdictions are 

considering or implementing approaches to incorporate locational value into programs.

6.3 Summary and Key Considerations 

States and utilities are undertaking analysis to determine locational value of PV and other DERs 

with the goal of encouraging more deployment in preferred areas of the grid to maximize value. 

The following are considerations for entities considering assessing DER locational value:

• Methods for assessing DER locational value are in their infancy. California and New York

have developed preliminary methods for quantifying locational value, but these methods are 

still being refined. 

• Distribution system infrastructure projects could be deferred by deploying DERs if a net 

benefit is derived. Even if locational value is derived solely by the net benefit of these 

considerations, it will serve as a better guide to DER deployment than, for example, only 
32

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considering hosting capacity. This notion is true because location is a primary determinant of 

the value of energy investments and services.

• The specificity and short timeline typical of a distribution infrastructure project could make 

use of conventional request-for-proposal processes challenging when seeking DER 

alternatives. Nonetheless, DER construction is highly scalable and relatively fast; efficient 

interconnection practices will further enhance deployment of DER alternatives.

• Locational value applies to all levels of granularity—ranging from the nodal level to the local 

or even regional level—and includes generation and transmission in addition to distribution.

• Incentives to defer utility infrastructure investment by deploying DERs might be desirable, if 

a net benefit is present. 
33

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7 Advanced-Inverter Requirements

Advanced or “smart” inverters have become available in recent years and can help ensure grid 

reliability, stability, and power quality (Text Box 2). Although most new inverters have 

advanced functionality, often those capabilities are not enabled or actively utilized because, 

historically, the limited deployment of DG such as PV did not necessitate grid support. 

Jurisdictions are developing rules to require use of these capabilities and deploy the functionality 

of advanced inverters.

7.1 Status and Experience to Date

Advanced-inverter requirements are being implemented at the regional and state levels, 

particularly in areas experiencing rapid DER deployment. The subsections below examine 

national inverter standards, advanced-inverter requirements in California, and requirements and 

related actions in other jurisdictions.

7.1.1 National Standards

Two organizations are prominent in developing national standards for DER interconnection: the 

Institute of Electrical and Electronics Engineers (IEEE) and UL (formerly known as 

Underwriters Laboratories). National standards are important because they often are referenced 

Text Box 2. Use of Inverters with PV

PV systems produce direct current (DC) whereas most appliances use—and most electric 

transmission and distribution systems carry and supply—alternating current (AC). Thus, an inverter is 

needed to convert DC to AC (see figure below). Contemporary inverters use power electronics to 

convert DC to AC by reversing voltage polarity at a rate of 60 times per second (60 Hertz). Advanced 

inverters typically are controlled by sophisticated microprocessors or digital signal processors,

allowing them to perform dozens of advanced functions that can enhance DER behavior, such as 

advanced anti-islanding protection, voltage and frequency ride-through, dynamic volt-var operations, 

ramp rate control, adjustable fixed power factor, and soft-start reconnection capability.

Schematic of inverter-based conversion of a PV system’s DC output (— in black area of 

inverter) into AC (~ in red area of inverter), with resulting AC output used for domestic 

purposes or exported to the grid.
34

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by state utility commissions. CPUC Electric Tariff Rule 21, for example, references IEEE 

Standard 1547 and UL Standard 1741 (CPUC 2014, 2–6).

Most jurisdictions have adopted IEEE Standard 1547 as the basis for DER interconnection with 

electric power systems. IEEE 1547 was first approved by the IEEE Standards Board and the 

American National Standards Institute in 2003. A related standard (IEEE 1547.1), which 

includes recommended testing requirements, was approved in 2005. The base IEEE 1547 

standard recently was revised, in part because of advances in inverter functionality. IEEE 1547-

2018 is now an active standard (IEEE 2018). Additionally, IEEE Standard P1547.1, which 

details conformance testing requirements for equipment that interconnects DERs with electric 

power systems, currently is being revised to reflect changes in the base standard. IEEE 1547.1a 

is an amendment to IEEE 1547.1, which is this standard’s most recent version (IEEE 2016). 

IEEE P1547.1 is significant in that, once approved and published, it will be referenced by both 

UL 1741 (see below) and state regulations such as CPUC Rule 21.

Another national-level standard is UL Standard 1741, which includes safety standards for 

electric shock, fire, and mechanical hazards, as well as a certification basis for interconnecting 

inverters with electric power systems (UL 2010). Most jurisdictions require UL 1741 

certification of equipment before it can be interconnected. As IEEE P1547.1 is being revised and 

published, UL 1741 Supplement A (UL 1741 SA) will be in effect in some states. UL 1741 SA,

finalized in September 2016, provides a certification test standard for equipment manufacturers 

and utilities that need advanced-inverter functionality prior to publication of the revised IEEE 

1547.1 (UL 2016). Upon publication of the revised IEEE 1547.1, UL 1741 will be harmonized 

with the IEEE standards and Supplement A likely will be eliminated (although there will be 

thousands of UL 1741 SA-certified devices in service for many years).

7.1.2 California’s Smart Inverter Working Group Process

The California Smart Inverter Working Group (SIWG) was formed in early 2013, at the initiative 

of the CPUC and the California Energy Commission (CEC), to address the reliability impacts of 

expanded DER adoption via advanced-inverter functionality. The group consisted of 

representatives of three principal stakeholder groups—utilities, DER manufacturers, and DER 

installers and aggregators. Its work consisted of three phases. Phase 1 focused on requirements 

for autonomous functions of inverter-based DERs. Phase 2 examined protocols needed for 

communication among utilities, DERs, and aggregators. Phase 3 focused on additional 

functionality of advanced inverters that might or might not require communications.

The Phase 1 SIWG recommendations were included in 2014 revisions to CPUC Rule 21, which 

addresses DER interconnection with distribution systems. Text Box 3 and this report’s Appendix 

show the seven functions that the CPUC requires advanced inverters to perform autonomously 

and which all interconnecting DERs are required to use as of September 8, 2017 (CPUC 2014, 4-

5; SIWG 2014, 21–35). These capabilities could enhance grid reliability and improve 

coordination between DERs and electric system operators. Other jurisdictions also have required 
35

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these capabilities. Many advanced-inverter models can execute these functions and are therefore 

approved for use in California as long as they have UL 1741 SA listing and labeling.29

 29 Go Solar California maintains an up-to-date listing of approved inverters at 

http://www.gosolarcalifornia.ca.gov/equipment/inverters.php (last visited March 27, 2018).

Text Box 3. Functions Advanced Inverters Must Perform Autonomously Under CPUC Rules

Low/High Voltage and Frequency Ride-Through Functions

These functions concern the connection status of a DER—such as a PV system—during anomalous voltage or 

frequency conditions. Concerning voltage, CPUC Rule 21, as informed by Phase 1 Recommendations of the 

SIWG, notes that there are voltage levels (and corresponding durations) for which a PV system should remain 

connected to a distribution system, and voltages and durations for which it should disconnect from a distribution 

system. Rule 21 therefore permits DER–distribution system connection during voltage anomalies of greater 

magnitude and for longer durations than in the past. Advanced inverters can accomplish this so-called voltage 

ride-through. Connection preservation is desirable because, given ever-increasing aggregate nameplate capacity 

of DERs, exacerbation of voltage anomalies (and possibly even outages) could occur if widespread 

disconnection of DERs takes place. Additionally, Rule 21 indicates that there are frequency levels (and 

corresponding durations) for which a PV system should remain connected to a distribution system, and 

frequencies and durations for which a DER should disconnect. Advanced inverters can also accomplish this socalled frequency ride-through.

Dynamic Volt/Var Operations

Dynamic volt/var operations are synonymous with dynamic reactive power compensation. With this capability, 

advanced inverters can counteract voltage deviations by either producing (in the event of a decrease in voltage 

on a distribution system) or absorbing reactive power (with increased distribution voltage). The former historically 

has been more common on feeders, particularly at increasing distances from a substation, but with increasing 

DER penetrations increased voltage also can be problematic.

Dynamic modification of voltage was prohibited prior to the 2014 revision of CPUC Rule 21. The SIWG 

recommendation for dynamic volt/var operations is that smaller DERs can operate over a power factor range of 

+/- 0.90 (see ”adjustable fixed power factor” in the Appendix for explanation of power factor). Dynamic volt/var 

operations can compensate for voltage impacts due not only to DERs, but also to motors and other types of load 

on a distribution system.

Communication Between DERs and Utilities.

Advanced inverters can enable two-way communication between DERs and utilities. DERs can be operated 

either autonomously or by a facility DER management system (FDEMS); a FDEMS can manage either multiple 

DERs at a single site or an aggregation of DERs at multiple sites. The SIWG offered the following Phase 2 

Recommendations: (1) DERs with advanced inverters must be capable of communications, (2) data 

requirements include those needed for advanced inverters to perform SIWG Phase 1 and Phase 3 

recommended functions, and (3) the abstract information model to be used for SIWG Phase 1 and Phase 3 

function communications is International Electrotechnical Commission (IEC) Standard 61850. IEC 61850 defines 

mechanisms for exchanging application messages. Other SIWG Phase 2 Recommendations include: (4) default 

protocol for individual DER—and FDEMS—utility communications will be IEEE 2030.5 (among its many uses, 

IEEE 2030.5 underlies remote programming of inverters), that (5) Transmission Control Protocol/Internet 

Protocol (TCP/IP) will be used, and all communication media can be used, for DER-utility communications, and 

(6) cybersecurity requirements will be, in part, based on IEEE 2030.5. 
36

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The SIWG developed Phase 2 recommendations for DERs in February 2015, which were 

subsequently incorporated into Rule 21 by the CPUC (SIWG 2015). The requirements address 

communication between DERs with advanced inverters and utilities (SIWG 2015, 5; see Text 

Box 3 for additional information on Phase 2 recommendations). Additionally, the SIWG released 

Phase 3 recommendations in March 2017 involving additional advanced-inverter functions; 

requirements for these functions are synchronized, where possible, with those of IEEE Standard 

1547-2018. An example of such synchronization is the requirement to use this standard’s “Cease 

to Energize” and “Return to Service” commands (SIWG 2017, 1–2). These recommendations 

have been approved by the CEC and are under consideration by the CPUC. The SIWG has a 

variety of resources related to CPUC Rule 21 available for further information (CEC n.d.).

7.1.3 Experiences of Other Jurisdictions with Advanced Inverters

The New England Independent System Operator (ISO-NE) is among the other jurisdictions 

working to realize the benefits of advanced inverters. It collaborated with the Massachusetts 

Technical Standards Review Group, which includes representatives from utilities operating in 

multiple New England states, to develop a source requirements document (SRD) and an 

implementation plan for inverter performance requirements. The SRD refers to UL 1741 SA in 

requiring advanced-inverter functions similar to those required by CPUC Rule 21. Regarding 

implementation, all inverter-based generation greater than 100 kW in capacity that applies for 

interconnection after March 1, 2018, must comply with the SRD. Generation of capacity up to 

100 kW that applies for interconnection after June 1, 2018, also must comply. Although ISO-NE 

will work with utilities and state regulators in implementing requirements of the SRD, it has 

noted advantages to having New England–wide requirements, including state-to-state uniformity 

for developers and simplified modeling of DERs for utilities and state regulators (ISO-NE 2018).

Hawaii has relatively high distributed PV penetration and has consequently been a leader in 

inverter requirements. In 2011, HECO (in conjunction with inverter manufacturers and the 

Hawaiian Public Utilities Commission) began a process to require low/high voltage ride-through 

and low/high frequency ride-through functionalities of grid-connected inverters. In addition, 

dynamic volt/var operations and communication between DERs and utilities are being 

considered (SEPA and EPRI 2015, 7). HECO now has a source requirements document requiring 

all of these inverter functions with the exception of communication capability (HECO 2018).

The Arizona Corporation Commission does not require advanced inverters, but several utilities 

in the state are exploring their value proposition. Arizona Public Service, for example, conducted 

a pilot project involving 1,600 residential PV systems with advanced inverters (SEPA and EPRI 

2015, 8). Dynamic volt/var operations were found to represent the best advanced-inverter 

function for feeder voltage management, particularly during summer in the utility’s territory.

Advanced inverters in the project were configured to prioritize reactive power over real power.

Additionally, the study showed that advanced-inverter vendor implementation of communication 

functionality generally was not fully compliant with IEEE Standard 2030.5, so augmentation 

with vendor or custom software was required. The intermittent nature of wireless networks also 

negatively impacted two-way communication (EPRI and APS 2017, vii–viii).

Another Arizona utility, Salt River Project, is conducting a pilot project involving approximately 

1,000 advanced inverters assigned to one of three categories: (1) employing advanced-inverter 

functions similar to those required by CPUC Rule 21 (functioning autonomously), (2) employing 
37

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advanced inverters with limited communication capabilities, and (3) employing advanced 

inverters with sophisticated capabilities to communicate with a facility DER management 

system. Performance of Category 3 inverters is of particular interest because it is anticipated that 

dynamic responses to real-time grid conditions will be enabled. Wireless communications will be 

used for Categories 2 and 3, which raises the question of whether intermittency will be 

problematic as was the case in the Arizona Public Service pilot project (SEPA and EPRI 2015, 

11–12).

Unsurprisingly, states with relatively low distributed PV penetrations are confining their 

activities to exploration of advanced-inverter deployment. Minnesota, for example, began its 

grid-modernization efforts in late 2014 with the e21 Initiative. Legislation in 2015 required 

utilities to identify transmission and distribution system inadequacies. In response, the Minnesota 

Public Utilities Commission established a docket related to the legislation. In early 2016, 

Commission staff issued a report on grid modernization that included discussion of advanced 

inverters and highlighted the functions required by CPUC Rule 21 (Minnesota PUC 2016b, 16–

17). The Minnesota PUC anticipates establishing its advanced-inverter function requirements by 

early 2019.

7.2 Lessons Learned: Design and Implementation Considerations

The following are some key considerations for jurisdictions seeking to address advanced-inverter 

requirements. 

7.2.1 Inverter Replacements and Cost Considerations

Requiring advanced-inverter-facilitated communications between DERs and utilities enables the 

United States to avoid certain negative experiences of other countries with high DER 

penetrations, but communications with small DERs might not be cost-effective. In 2010, it was 

determined that in a grid event potentially affecting Germany and Italy, 9,000 MW of the 

14,000 MW of aggregate distributed PV generation capacity were at risk of rapidly 

disconnecting from the grid. The European grid can only withstand an instantaneous loss of 

3,000 MW. Thus, the German government passed an ordinance in 2012 requiring either output 

reduction or gradual shutdown of output by distributed PV systems during over-frequency 

events. Retrofitting of inverters was required for more than 300,000 PV systems. For many of 

these systems, changes in operating software or inverter operating parameters were sufficient to 

achieve this retrofitting. Inverter replacement, however, was required for older inverters. 

Estimates of the cost of the German retrofitting range from $90 to $200 million (McAllister

2016, 12).

In 2014, a large proportion of the Hawaiian island of Oahu’s aggregate PV capacity was at risk 

of rapidly disconnecting from the grid during over-frequency and under-frequency events, which 

led to reprogramming of approximately 800,000 inverters. Fortunately, prior deployment of 

advanced inverters with remote programming capability permitted updating of low- and highvoltage and frequency ride-through functions for many of the installed PV systems. Remote 

reprogramming was performed with savings for ratepayers estimated at nearly $50 million. This 

work was facilitated by Hawaiian Electric Companies Rule No. 14, which requires remote 

inverter programming capability (McAllister 2016, 12–13).
38

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7.2.2 Jurisdictional Authority

An unresolved issue is which entity—state PUC, utility, balancing authority (frequently a utility 

in the western United States), or regional reliability organization (currently Peak Reliability in 

the West)—should require advanced-inverter functions. As discussed previously, entities with 

authority encompass the range of possibilities. Considerations include the functions to be 

required as well as function specifics. For example, for low- and high-voltage ride-through, 

specifics would include voltage ranges and corresponding must-stay-connected durations.

Allowing state PUCs to require advanced inverters, such as through reference to UL 1741 SA, 

will advance advanced-inverter technology to the field. Ensuring that the inverters behave 

according to the bulk power system requirements is an important factor that can be supported by 

the North American Electric Reliability Corporation (NERC), the local ISO, or Peak Reliability. 

Requiring advanced-inverter functionality is the first step, but the setpoints of those inverters 

must be determined carefully by the local utility in coordination with the bulk system operators. 

7.3 Summary and Key Considerations

Advanced inverters offer numerous functions that could enhance grid reliability by mitigating 

concerns associated with high DER penetrations on distribution systems. Thus, DER-associated 

equipment (advanced inverters) can mitigate concerns associated with DERs. Prominent 

examples of these functions are low- and high-voltage ride-through and dynamic volt/var 

operations. 

• National standards such as IEEE Standard 1547 can be used by regulatory entities in 

states and regions where DER penetration is increasing. Adopting IEEE 1547-2018,

which details the advanced-inverter functions required by CPUC Rule 21 and ISO-NE’s 

SRD, would enable several functions predicted to enhance grid reliability. 

• Adoption of UL 1741 SA provides a means of certifying inverters that are capable of the 

functions specified by IEEE 1547-2018.

• Advanced-inverter deployment also could result in cost savings owing to remote, rather 

than onsite inverter reprogramming. IEC Standard 61850 and IEEE Standard 2030.5 

facilitate remote inverter reprogramming.

• Standards such as IEC 61850 and IEEE 2030.5 also facilitate two-way communication 

between DERs and utilities. Communication might be desirable in the future for utility 

control of DERs.
39

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8 Application Automation and Process Improvements

The application process can be a significant bottleneck that can delay interconnection and lead to 

additional costs for the customer, developer, or utility. To minimize delays associated with the 

application process and reduce staff time required to process each application, many utilities

have improved internal operations, and some utilities have adopted online application submission 

pathways that can facilitate a more streamlined and automated application process.

Improvements can simplify application submission for developers and expedite utility 

application review and enable the utility to process a greater volume of requests efficiently.

Online application portals or other enhancements to application-submission methods can 

improve customer service and streamline application submission for the customer.

8.1 Status and Experience to Date

Utilities have taken a number of different paths to enhance application submission and 

processing. For example, some utilities allow customers to apply through an online portal. Figure 

4 shows the application-submission methods across 25 utilities in the West. Online applications 

facilitate submission and reduce or eliminate data entry by the utility, and they also create a 

digital platform that can be used to streamline or automate the application process. For example, 

some utilities have integrated online portals with existing customer databases to help expedite 

application submission and reduce customer errors. Additionally, in some cases, these online 

portals allow electronic payment and signatures, which simplifies application submission. Some 

utilities use commercial software, such as Salesforce, GridUnity, or PowerClerk, to run 

application processes. Other utilities have developed software in-house. Some utilities also 

modified internal operations to facilitate faster and more-efficient application processing.

Figure 4. Western utility application submission pathway

8.2 Approaches to Process Improvements and Automation

Utilities interviewed for this project reported a range of different considerations in weighing 

whether to implement online application submission and process automation. A few utilities 

reported that application submittal and processing were still paper-based because application 

volume was not high enough to justify investment in an online platform. Conversely, some 

utilities cited high application volumes as the reason an online system was adopted. Additionally, 

0

2

4

6

8

10

12

14

16

18

Not online Email Online (portal)

Number of 

utilities

Residential Small commercial
40

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back-end integration and automation are deployed by many utilities for a few reasons, including 

to improve workflow management and coordination among departments, give customers access 

to more granular information, and automate prescreening or screening. Automation of technical 

review screens, though potentially costly and time-consuming to implement, could further reduce 

the burden of processing and reviewing interconnection requests. A few of the utilities 

interviewed indicated that they had automated some prescreening or initial technical screens. 

Some utilities noted that they had considered or were considering incorporating automated 

screening, but they highlighted the technical complexity of implementation and cost as obstacles.

Table 4 highlights some of the practices implemented by utilities to improve the application 

submittal and review process.

Table 4. Utility Application Processing Improvements

Process 

Improvements Automation

Organizational 

Improvements

• Application error 

reports given to 

installers

• Reduce 

inspections by 

using them only if 

needed

• Online payment of 

application fee

• Single engineer 

handles all the 

applications for 

systems less than 

a certain size

• Systems below a 

certain size are 

only reviewed by 

the engineering 

department if there 

is an issue

• Internal workflow 

management is 

automated

• Inspector can 

automatically 

upload 

certifications of

passed building 

inspection to utility 

database

• Initial engineering 

review is 

automated for 

small projects

• Automated 

system size 

screening by 

comparing to 

usage data

• Organizational 

emphasis on being 

process oriented

• Single point of contact

for contractors to

streamline 

communication

• Simple applications are 

reviewed by a thirdparty company

• Ongoing staff training 

on application system 

and processes

• For internal 

processing, 

applications are 

divided up by project 

size to make workflow 

more efficient

For utilities that do not have high enough application volumes to justify investing in an online 

system or automation, there are steps to improve processes. For example, a utility can create a 

fillable PDF for developers to submit applications, which can both streamline submission and 

reduce developer errors. Allowing developers to submit applications by email or fax and sign 

documents and make payments electronically, rather than by mail, also can help a utility start 

project reviews more quickly. Additionally, utility workflow improvements can expedite 

processing for utilities that do not allow online submission—for example, National Grid in 

Massachusetts, which does not have an online application submission portal, has well-defined 

procedures for managing and manually processing applications (Barnes et al. 2016, 25). 
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8.3 Design and Implementation Considerations

Many utilities have implemented online application systems, frequently without a state mandate. 

An online application system can have a clear value proposition in some cases, especially for 

larger utilities that process a high volume of applications. It can reduce the staff time dedicated 

to processing each application, expedite interconnection timelines, and streamline the 

interconnection process from both the utility’s and customers’ perspectives. However, 

implementing an online application system can require a high upfront cost, both financially and 

in terms of utility back-end software and data-management tools. As a result, smaller utilities 

might not have the financial incentive to invest in an online system, especially if application 

volume is low. There still are steps that utilities can take outside of online application portals, 

such as implementing process improvements, facilitating email submission of applications, and 

allowing online payment and electronic signatures.

8.4 Summary and Key Considerations

Online application portals and automation of parts of the application process can provide benefits 

to both customers and utilities. For customers, this can simplify application submission, give 

them access to information about application review status, and help utilities process applications 

more quickly. They can also help utilities streamline application processing and review and 

reduce cost and staff time spent handling applications.

• Many utilities have adopted online application portals and taken steps to streamline or 

automate application processing, often without regulatory directive.

• Because adopting or developing an online application process can take a substantial 

upfront investment of time and cost, it might not make financial sense for all utilities. 

For example, small utilities with low application volumes might not be able to justify the 

cost.

• There are a number of enhancements beyond an online application portal and basic backend data integration that a utility could implement to expedite application processing 

further. Regulators could consider supporting utility efforts to develop or adopt 

additional enhancements to utility-application processing systems.
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This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

9 Summary and Conclusions 

Rapid adoption of distributed PV and other DERs in some states is creating new challenges and 

causing regulators and utilities to reconsider aspects of interconnection policy. Innovative 

approaches are being used to address issues related to cost equity and transparency, new 

technologies, grid conditions, as well as communications with and responsiveness of inverterbased systems. The following approaches are being used to address emerging issues in states 

experiencing growth in distributed resources and could have applications in other areas that 

could face these issues in the future:

• A few states have adopted policies that provide greater transparency and certainty of 

interconnection costs to customers earlier in the process, which can benefit both utilities and 

developers by eliminating projects from the interconnection queue that are likely to be 

uneconomic. For example, Massachusetts has a cost-envelope policy that limits the 

customer’s liability for upgrade costs to within 25% of the utility’s estimate, California has 

an opt-in cost envelope pilot, and Utah limits study costs. Making accurate upgrade cost 

estimates early in the interconnection process is challenging, but additional study time and a 

site visit can help improve accuracy. For policymakers, key issues are balancing the tradeoff 

between the challenges for utilities in making accurate estimates early in the process and the 

need for more cost certainty for customers. Another consideration is addressing cost overruns 

that could be outside of the utility’s control. To encourage more transparency in costs, 

California also requires utilities to publish cost guides that provide representative cost data 

for different distribution system upgrades. Other jurisdictions have reporting requirements. 

• In a few utility areas or states, policies are being developed to share grid-upgrade costs 

across a group of DER projects (or current and future projects) to reduce the magnitude of 

the cost burden for individual projects and address inequities of applying upgrade costs to a 

single project when other projects also benefit. For example, National Grid in New York is 

sharing substation upgrade costs proportionally across a group of projects that are enabled by 

the substation upgrade and over a certain size threshold. In Massachusetts, a group of 

projects is studied jointly, and costs for system upgrades are allocated proportionally based 

on system sizes. Utility-line-extension policies represent another potential model. Under 

some policies, the utility covers a portion of upgrade costs with a construction allowance that

is recovered from the rate base, and the customer pays any cost exceeding the allowance. 

• With the declining costs of storage, more jurisdictions are beginning to see requests for 

behind-the-meter storage systems, often coupled with PV, prompting some states and utilities 

to develop new interconnection requirements for these systems. Evaluating the potential 

impact of a storage or PV plus storage system can be more complex than for standalone PV 

because storage can operate as both a load and a generator. For this reason, some states have 

added storage under the definition of a generator in interconnection standards to clarify the 

treatment of storage. The operation and control of charging and dispatch of storage systems 

coupled with PV can have implications for grid impacts and grid interconnection. Some 

states (e.g., California, Nevada) allow customers to specify charging and export behavior in 

the interconnection application, which can influence technical review requirements. An issue 

that could benefit from greater regulatory clarity is how costs would be assigned to a storage 

project that triggers upgrades because of its additional load. 

• Hosting-capacity analysis is being used in some jurisdictions to provide more accurate 

assessments of how much distributed PV and other DERs can be added to the distribution 
43

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

grid before a substantial upgrade is needed. There are a variety of use cases for hostingcapacity data and maps, including distribution system planning, informing customers about 

grid conditions, and potentially expediting interconnection. Although feeder-specific 

assessments can provide more accurate estimates of hosting capacity than current rule-ofthumb estimation, there is a range of analytic approaches (e.g., simplified equations to 

complex iterative power-flow analysis) that yield varying levels of accuracy. To date, 

methods vary across jurisdictions and approaches continue to evolve. The level of analytic 

rigor required can vary depending on both the use case and the expected DER growth. For 

example, methods that are best for distribution system planning might differ from those that 

are useful for streamlining interconnection requests. Frequency of updates can impact the

usefulness of data, and current practices vary considerably (e.g., HECO updates maps daily,

New York utilities update data annually). Jurisdictions could benefit from improving hostingcapacity determination prior to anticipated increases in interconnection requests.

• Some states are undertaking locational value assessments to determine where PV and other

DERs might be able to avoid infrastructure costs and exploring tariffs or compensation 

mechanisms. Groups in both California and New York have developed preliminary methods 

for quantifying locational value, but these methods are still being refined. Efforts have been 

primarily focused on assessing the value of deferred or avoided transmission and distribution 

system upgrades, but other avoided cost categories could be incorporated into locational 

value assessment. Even if locational value is derived solely from the net benefit of deferral 

value, it can provide a more comprehensive guide to DER deployment than, for example, 

only considering hosting capacity. Locational value estimates could be used to drive 

deployment in preferred locations through tariffs, procurement processes, and targeted 

programs (e.g., community solar programs). New York has incorporated locational elements 

in its value stack tariff for DER export compensation. Overall, important considerations for 

undertaking locational value assessment are the use cases of the data, the scope of categories 

to consider, and the accuracy of calculation methods needed.

• Several areas have developed advanced-inverter requirements to ensure that grid-connected, 

inverter-based generators can meet grid needs and have communications capabilities to 

ensure future grid reliability. Advanced inverters offer numerous functions (e.g., voltage and 

frequency ride-through capabilities, active voltage support via reactive or real power) that 

could enhance grid reliability and mitigate concerns associated with high DER penetrations 

on distribution systems. Advanced-inverter deployment could result in cost savings owing to 

remote rather than onsite inverter reprogramming, if needed. Advanced inverters can also 

facilitate two-way communication between DERs and utilities, which might be desirable in 

the future for utility control of DERs. Adoption of the national IEEE Standard 1547-2018, 

which details the advanced-inverter functions now required by some regulatory entities, 

would enable several functions predicted to enhance grid reliability.

• Many utilities that have experienced growth in DER applications have taken steps to 

streamline or automate application processing. Efforts to improve application-processing 

efficiency have included development of online application processing and implementing 

software solutions to improve the efficiency of internal processing. These improvements 

have resulted in faster processing and improved communications about the status of 

applications both with the customer and across utility departments. Investments in process 

improvements could be warranted for utilities expecting growth in application volumes, but 
44

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

costs of some software upgrades could be prohibitively costly for small utilities with low 

application volumes. 
45

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

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

Appendix. Other Functions Advanced Inverters Must 

Perform Autonomously Under CPUC Rules

Anti-Islanding Protection

This protection ensures that, when a distribution system is unintentionally de-energized, a DER 

does not re-energize this unintentional electrical island. An electrical island develops when a 

portion of the grid, typically a distribution system, is isolated from the remainder of the grid. An 

island, however, can continue to operate if a DER provides its output to the island. Mandatory 

disconnection of a DER prevents damage to persons and equipment involved in repairing the 

electrical island by maintaining a de-energized island. Inverters can detect electrical islands via

three general detection approaches: passive, active, and remote (i.e., at the utility level). The first 

two approaches use capabilities residing within an inverter. Passive methods, which resemble 

how utility low- and high-voltage or frequency relays function, involve monitoring certain 

variables (e.g., voltage) on the interconnected distribution system and stopping the conversion of 

DC to AC if a variable exhibits sufficient deviation from its normal range. Active methods

attempt to introduce a disturbance to the interconnected distribution system and monitor the 

system’s response. Under normal operation, an attempted disturbance will not disturb the 

stability of distribution system variables such as voltage. If an electrical island is present, 

however, a variable might not exhibit stability. If instability is present, an inverter will stop 

converting DC to AC.

Ramp Rate Control

A DER such as a PV system can control, via an advanced inverter, the rate at which its power 

output to a distribution system increases or decreases, thus smoothing transitions between power 

output levels. Importantly, ramp rate control allows for more orderly transitions in the case of 

aggregated DERs that could otherwise negatively impact a distribution system. Power-quality 

issues on a distribution system can develop without ramp rate control.

Adjustable Fixed Power Factor

Real power, the product of voltage and current expressed in units of watts, is one type of power 

present in distribution systems along with reactive power. The vector sum of real and reactive 

power equals apparent power, and power factor is the ratio of real to apparent power. Although a 

power factor of 1.0 (i.e., no reactive power present) is optimal for efficient system operations, it 

rarely is achievable in distribution systems because loads and DERs can generate reactive power.

The presence of large numbers of DERs on a distribution system can cause voltage to increase

owing to apparent power flow from DERs toward the substation. Such a voltage increase can be 

managed by setting DER power factor to absorb a small amount of reactive power and reduce the

increased voltage. Conversely, DER power factor can be set to produce reactive power on 

circuits where reduced voltage at the distal end of the distribution system is an issue.

Reconnection by Soft-Start Methods

Soft-start methods refer to reconnection of DERs to a distribution system following an outage. 

Two soft-start approaches to reconnection—staggering the reconnection of DERs to a 

distribution system or ramping aggregate DER reconnection—will mitigate overly large 
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increases in voltage or frequency on the distribution system. Although either approach avoids a 

sharp increase in aggregate DER power output onto a distribution system during reconnection,

staggered reconnection does not discriminate among system capacities. Thus, the presence of a 

single, large-capacity DER might induce local voltage or frequency disturbances. Therefore, 

soft-start ramping of aggregate DER reconnection is preferred because increases in DER output 

are very predictable regardless of DER capacity.