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

Industry Perspectives on 

Advanced Inverters for U.S. Solar 

Photovoltaic Systems: Grid 

Benefits, Deployment Challenges, 

and Emerging Solutions

Emerson Reiter, Kristen Ardani, and

Robert Margolis

National Renewable Energy Laboratory

Ryan Edge

Solar Electric Power Association

Technical Report

NREL/TP-7A40-65063

September 2015
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

Golden, CO 80401

303-275-3000 • www.nrel.gov

Industry Perspectives on 

Advanced Inverters for U.S. Solar 

Photovoltaic Systems: Grid 

Benefits, Deployment Challenges, 

and Emerging Solutions

Emerson Reiter, Kristen Ardani, and

Robert Margolis

National Renewable Energy Laboratory

Ryan Edge

Solar Electric Power Association

Prepared under Task No. SM13.0532

Technical Report

NREL/ TP-7A40-65063

September 2015
NOTICE

This report was prepared as an account of work sponsored by an agency of the United States government. 

Neither the United States government nor any agency thereof, nor any of their employees, makes any warranty, 

express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of 

any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately 

owned rights. Reference herein to any specific commercial product, process, or service by trade name, 

trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, 

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

expressed herein do not necessarily state or reflect those of the United States government or any agency thereof.

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

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

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Acknowledgments

The authors thank the following individuals and organizations for their contributions to and 

review of this work: John Berdner (Enphase), Kenneth Boyce (Underwriters Laboratory), 

Michael Coddington (National Renewable Energy Laboratory), Babak Enayati (National Grid), 

Tracy Miehlke (PJM), Houtan Moaveni (New York Power Authority), Erika Myers (Solar 

Electric Power Association), John Sterling (Solar Electric Power Association), Jarrett Zuboy 

(consultant). In particular, we thank Miriam Makhyoun (formerly with Solar Electric Power 

Association) for her help in developing the interview protocol and setting up the interviews. This 

work was supported by the U.S. Department of Energy under contract number DE-AC36-

08GO28308.
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List of Acronyms

AGC automatic generator control

AMI advanced metering infrastructure

AMR automatic meter reading

APS Arizona Public Service

AZCC Arizona Corporation Commission

CAGR compound annual growth rate

CEC California Energy Commission

CPUC California Public Utilities Commission

DER distributed energy resource

DGPV distributed-generation PV

DRP distribution resource plan

IEEE Institute of Electric and Electronics Engineers

NEC National Electrical Code

NREL National Renewable Energy Laboratory

PCC point of common coupling

PV photovoltaic

SEPA Solar Electric Power Association

SIWG Smart Inverter Working Group

TEP Tucson Electric Power Company

UL Underwriters Laboratories

VAR volt-ampere reactive

WEIL Western Electric Industry Leaders
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Executive Summary

As the penetration of distributed-generation photovoltaics (DGPV) has risen rapidly in recent 

years, utilities and other electric-system stakeholders have become increasingly concerned about 

the resulting impacts on grid reliability. At the same time, advanced inverters—which can

modulate output and communicate actively with grid operators—are increasingly seen as a way 

to enhance grid stability and enable wider adoption of DGPV. Nearly half of the utilities that 

responded to a 2015 Solar Electric Power Association (SEPA) survey question about advanced 

inverters were either implementing or considering an advanced inverter project. Despite the 

interest in advanced inverters, however, relatively few utilities have widely deployed the devices

to date.

To clarify current utility strategies and other considerations related to advanced inverter 

deployment, we interviewed 20 representatives from 11 leading organizations closely involved 

with advanced inverter pilot testing, protocols, and implementation. Included were 

representatives from 7 utilities, a regional transmission operator, an inverter manufacturer, a 

leading solar developer, and a consortium for grid codes and standards. Interview data represent 

geographically the advanced inverter activities identified in SEPA’s prior survey results—most 

interviewed utilities serve California, Arizona, and Hawaii, though we also interviewed others 

from the Northeast, Mid-Atlantic, and Southeast.

Interview participants identified several benefits they expect from advanced inverters as well as 

several challenges to implementing the technology.

• Benefits

o Improvement in system reliability and power quality

o Increase in distribution system visibility through sensor data

o Potential deferral of utility grid capital investments.

• Challenges

o Involvement in ongoing, multi-party engagement

o Inability of standards to keep pace with technological advances

o Need for new communications infrastructure and protocols

o Lack of compensation mechanisms for ancillary services.

This report provides additional context on the latter three challenges—which the participants 

identified as being the most important—and discusses emerging solutions.

The updating of electric-system standards generally proceeds slowly and deliberately, and the 

outdated versions of two particular standards—UL 1741 (addressing equipment safety) and IEEE 

1547 (addressing interconnection)—are delaying use of advanced inverters nationwide. 

However, California’s urgent need to accelerate advanced inverter deployment is helping 

stimulate sweeping revisions of the standards. We anticipate these pending updates will not only 

protect individual systems and the grid from the new functions of advanced inverters, but will 

also enable the inverters to provide active grid support. Additionally, the updated standards will

likely promote progress toward the mass-production of advanced inverters in which a common 
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set of advanced functions has already been enabled, satisfying the desire indicated by interview 

participants for “off-the-shelf” products. In any case, the updates should eliminate the standardsrelated barriers to advanced inverter deployment.

Another critical challenge is establishing the communications capabilities needed to realize the 

grid-support potential of advanced inverters. Many communications options are available, and as 

the capabilities of the options increase so does the cost. To balance the cost-benefit tradeoff, 

some of the utilities we interviewed are planning hybrid approaches that relegate advanced 

inverters in certain areas to autonomous or low-bandwidth operation while enabling robust 

connectivity on inverters in other areas. Overall, utility participants agreed that the benefits of 

establishing communications infrastructure for advanced inverters outweigh the associated 

complexity and costs.

Lastly, the lack of mechanisms to compensate non-utility photovoltaic (PV) owners for 

providing ancillary services presents a challenge to realizing the full potential of advanced 

inverters. Some utilities are experimenting with utility ownership and control of PV systems 

mounted on customers’ rooftops. Under this framework, utilities may be able to streamline 

operational logistics, avoid complex financial compensation issues, and more quickly assess the 

value of the services received from the advanced inverter–enabled systems. Results from such 

projects then can inform the development of future mechanisms for compensating non-utility PV 

owners. This is important because non-utility ownership seems likely to remain the dominant 

form of distributed PV deployment in the foreseeable future.
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Table of Contents

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

1.1 What Makes an Inverter “Advanced?”.......................................................................................... 1

1.2 Advanced Inverter Deployment Trends........................................................................................ 2

2 Methodology ......................................................................................................................................... 3

3 Utility Benefits of Advanced Inverters ............................................................................................... 4

3.1 Improvement in System Reliability and Power Quality................................................................ 4

3.2 Increase in Distribution System Visibility Through Sensor Data ................................................. 5

3.3 Potential Deferral of Utility Grid Capital Investments.................................................................. 5

4 Advanced Inverter Deployment Challenges and Emerging Solutions............................................ 5

4.1 Involvement in Ongoing, Multi-party Engagement ...................................................................... 6

4.2 Inability of Standards to Keep Pace with Technological Advances.............................................. 6

4.2.1 California Rule 21 and the Smart Inverter Working Group............................................. 7

4.2.2 UL 1741 SA ..................................................................................................................... 8

4.2.3 IEEE 1547 Full Revision.................................................................................................. 9

4.3 Need for New Communications Infrastructure and Protocols ...................................................... 9

4.3.1 Relationship Between Advanced Functionality and Communications.......................... 10

4.3.2 Elements of a Communications Infrastructure............................................................... 11

4.4 Lack of Compensation Mechanisms for Ancillary Services....................................................... 12

5 Arizona’s Deployment Strategies and Solution Pathways............................................................. 13

6 Conclusion .......................................................................................................................................... 15

References................................................................................................................................................. 17

Appendix A. SEPA’s Annual Solar Market Survey Instrument 2015 ................................................... 20

Appendix B. Utilities Implementing or Exploring Advanced Inverters (from SEPA 2015 Survey) ... 21

Appendix C. NREL-SEPA Interview Questions Used for Data Collection........................................... 23

Appendix D. Overview of Advanced Inverter Deployment Standards................................................. 26

Appendix E. Description of Communication Layer Options ................................................................ 28
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List of Figures

Figure 1. Map of utilities implementing or considering implementing advanced inverters (Source: SEPA 

2015 utility survey). ................................................................................................................. 3

Figure 2. How regulations for distributed generation depend on IEEE 1547 and UL 1741......................... 7

List of Tables

Table 1. Select Common Functions of Advanced Inverters ......................................................................... 2

Table 2. Autonomous Versus Non-Autonomous Inverter Functions.......................................................... 11

Table 3. Utility Options for Communications Infrastructure...................................................................... 12
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1 Introduction

Unprecedented reductions in solar photovoltaic (PV) equipment costs have driven rapid growth 

in the U.S. distributed-generation PV (DGPV) market, from ~4.3 GW of total installed capacity 

in 2012 to ~10.0 GW as of the second quarter of 2015. This represents a 45% compound annual 

growth rate (CAGR) in the residential market and a 44% CAGR in the commercial market 

(BNEF 2014, Deutsche Bank Markets Research 2015, GTM Research and SEIA 2015).

Large quantities of DGPV can challenge utility-grid reliability by increasing the variability and 

uncertainty of the system net load and increasing the potential for overvoltages (Denholm et al.

2014). Advanced or “smart” inverters could address many of these challenges by actively 

mitigating unwanted grid impacts caused by DGPV, thus enabling wider adoption of PV and

ensuring grid stability. In August 2013, top executives from 16 of the largest utilities in the 

western United States—collectively the Western Electric Industry Leaders (WEIL)—signed on 

to support advanced inverter functionality for all new solar interconnections (WEIL Group 

2013). Also in 2013, the California Public Utilities Commission (CPUC) began the process of 

amending Rule 21 in parallel with the Institute of Electric and Electronics Engineers’ (IEEE) 

update to its IEEE 1547 standard. Both Rule 21 and IEEE 1547 govern the interaction of 

inverters with the grid, and the revisions to both will enable advanced inverter functionality.

Since 2013, Rule 21 and IEEE 1547 have undergone limited updates or amendments, but more 

significant changes are still pending, and some utilities are moving forward with their own pilot 

programs to test the grid-support functions of advanced inverters. Despite these ongoing efforts,

however, technical barriers continue to prevent broad adoption of advanced inverters, and policy 

and business models still must evolve to maximize the technology’s potential. 

This report clarifies emergent protocols and considerations for advanced inverter deployment.

The remainder of this introduction defines advanced inverter functionality and characterizes 

broad deployment trends as context for our interview results. Section 2 describes our 

methodology. Section 3 summarizes the advanced inverter benefits discussed in our interviews.

Section 4 summarizes the challenges to advanced inverter deployment from our interviews,

provides context on key challenges, and discusses actual and potential solutions. Section 5

illustrates advanced inverter deployment challenges and solutions through the experience of two 

Arizona utilities. Finally, Section 6 concludes and identifies areas for future research.

1.1 What Makes an Inverter “Advanced?”

All inverters used in grid-connected PV systems convert electricity from a direct-current source 

to alternating-current output that matches the voltage, frequency, and phase of the interconnected

utility grid to ensure safety and reliability. Under current electrical codes and standards, inverters

must cease to energize the grid if frequency and voltage fall outside of set parameters, and they

cannot actively change the voltage of the grid without coordination with the local electric utility.

Advanced inverters, in contrast, can modulate their output to actively support the grid in many 

novel ways. They can continue to operate within wider ranges of frequency and voltage, they can 

vary their power factor, and they can enhance the power quality and performance of the local 

grid. For instance, previous studies have shown that up to 100% more PV can be accommodated 

using advanced reactive power controls such as volt-VAR and constant power factor (e.g., 

Coddington et al. 2012). An advanced inverter’s physical hardware is virtually identical to that of 
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standard inverters; the key differences are dictated by the software that governs the advanced

functionality. Table 1 provides a select list of common advanced inverter functions (Seal 2014).

Table 1. Select Common Functions of Advanced Inverters

Function Description

Connect/disconnect Physically connects or disconnects from the grid

Adjust maximum generation level Sets maximum generation

Adjust power factor Issues a power factor angle value

Volt-VAR mode Adjusts reactive power output

Frequency ride-through Sets the frequency parameters for operation

Voltage ride-through Sets the voltage parameters for operation

Event/history logging Requests event logs

Status reporting Requests inverter status

Direct costs for advanced inverter implementation are expected to be negligible for U.S. electric 

utilities. Most advanced functions can be enabled by manufacturers at virtually no cost because

the inverters are controlled by embedded firmware that easily can be modified according to grid 

codes or hardware standards (such as Rule 21, IEEE 1547, and UL 1741, covered in section 4.2, 

below). Deploying telecommunications infrastructure or retrofitting existing inverters, however, 

adds substantial costs. Additionally, oversizing inverters to enable reactive power support 

without a reduction in real power output can increase the inverter cost for a given PV system.

1.2 Advanced Inverter Deployment Trends

In the first quarter of 2015, the Solar Electric Power Association (SEPA) surveyed 274 utilities 

about their solar activities (SEPA 2015). Of the 122 responses, 15 utilities said they were 

currently implementing a project or program involving advanced inverters, and another 43 said

they were planning, considering, or researching deployment of advanced inverters in some 

capacity (see Appendix A for the SEPA survey language). Thus, nearly half of those responding 

to this question viewed advanced inverters as a component of their solar strategies in the coming 

years.

Most of the 15 utilities who responded to the SEPA survey indicated that they are currently 

implementing advanced inverters to serve the states with the most mature solar markets, such as 

Hawaii, California, and Arizona. Additionally, National Grid in the Northeast, subsidiaries of 

Pepco in the mid-Atlantic, and Avista Utilities in the Northwest are pursuing the technology. 

Duke Energy, Public Service Electric & Gas, Los Angeles Department of Water and Power, and 

Austin Energy are among the 43 utilities planning, considering, or researching deployment of

advanced inverters in some capacity.

Figure 1 summarizes SEPA’s survey findings related to advanced inverter deployment. A

complete list of respondents that were implementing or exploring advanced inverters is included 

in Appendix B.
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Figure 1. Map of utilities implementing or considering implementing advanced inverters

(Source: SEPA 2015 utility survey).

2 Methodology

To date, most advanced inverter literature has addressed the functions of the technology (Seal 

2014) and the associated grid benefits utilities seek (Davidovich and Sterling 2014). Much has 

also been written about Germany’s recent system-wide advanced inverter retrofit (Wirth 2015,

EPRI 2014). This literature effectively frames the challenges of integrating large concentrations 

of intermittent resources and some of the mitigation measures inverters can provide. Other 

literature generally describes the remaining regulatory and technological barriers to DGPV 

adoption, including the need for utility and solar industry business models to evolve so that 

advanced inverters can facilitate solar resource integration (Bird et al. 2013). Less has been 

written about real-world performance or implementation in the United States, because 

deployment has been limited. This report addresses gaps in the literature by summarizing the 

current state of active utility initiatives and pilot projects, discussing stakeholders’ perceptions of 

the benefits of advanced inverters, describing the recent evolution of rules and standards 

governing advanced inverter use, identifying the short- and long-term market barriers to widescale adoption, and providing real-world examples of solutions to the barriers identified.
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To capture these insights, the National Renewable Energy Laboratory (NREL) and SEPA 

interviewed 20 representatives from 11 leading organizations closely involved with advanced 

inverter pilot testing, protocols, and implementation. Included were representatives from 7 

utilities, a regional transmission operator, an inverter manufacturer, a leading solar developer, 

and a consortium for grid codes and standards. Interview data represent geographically the 

advanced inverter activities identified in SEPA’s prior survey results—most interviewed utilities 

serve California, Arizona, and Hawaii, though we also interviewed others from the Northeast, 

Mid-Atlantic, and Southeast. Interview questions focused on gaining a deeper understanding of 

the benefits utilities seek from advanced inverter functions, current challenges to advanced 

inverter deployment, and the status of rules and standards governing inverter use. The full list of 

interview questions is included in Appendix C. Aggregate results in the following two sections 

highlight common themes and key takeaways from the interviews, but individual participant 

information remains confidential.

3 Utility Benefits of Advanced Inverters

The interview results reveal several common themes related to the utility benefits of advanced 

inverters, which are discussed in this section:

• Improvement in system reliability and power quality

• Increase in distribution system visibility through sensor data

• Potential deferral of utility grid capital investments.

3.1 Improvement in System Reliability and Power Quality

Nearly all utility representatives who participated in the interviews indicated a strong interest in 

using advanced inverter functionality to maintain system reliability and local power quality while 

increasing the contribution of DGPV to the generation portfolio. Specifically, utilities with high 

DGPV penetration commonly sought expanded voltage and frequency ride-through capabilities.

These two functions were often characterized as “low-hanging fruit,” meaning that the utilities 

could realize significant system benefits at a low implementation cost; the inverters can provide 

the ride-through support autonomously and without potentially expensive data connectivity with 

the utility. Currently, both the Phase 1 recommendations of the Smart Inverter Working Group 

(SIWG) for California’s Rule 21 update and the 2014 amendment to IEEE 1547 (IEEE 1547a2014) establish frameworks for grid-tied PV systems to deliver expanded voltage and frequency 

ride-through.

More advanced power-quality features require more robust software and communications 

solutions that enable utilities to maximize advanced inverters’ capabilities (see Section 4.3). The 

utilities interviewed expressed broad interest in tapping distributed inverters for volt-ampere 

reactive (VAR) support as a voltage-control tool, but their planned approaches differed. Some 

described a static, non-unity power factor for inverters on feeders with consistent voltage 

characteristics, whereas others would alter the power factor seasonally or even dynamically 

when integrated with a distribution management system or distributed energy resource (DER)

management system.
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3.2 Increase in Distribution System Visibility Through Sensor Data

Many utility participants anticipate using telemetry data from inverters deployed across the 

distribution system to optimize grid operations, increase visibility, improve DER integration, and 

reduce overall operating costs for the distribution system. Many participants, however, cautioned 

that gathering such granular data can pose collection, storage, and processing challenges if the 

data are used to inform distribution-management practices (see Section 4.3). Gathering and 

storing such data also necessitates a conversation regarding data privacy and cybersecurity.

3.3 Potential Deferral of Utility Grid Capital Investments

Interconnecting DGPV to the utility’s grid may necessitate adding or upgrading transformers, 

wires, voltage-regulation devices, control systems, and protection equipment (Denholm et al. 

2014). Voltage-regulation devices, in particular, are subject to additional wear and tear with 

DGPV because of the increased potential for over-voltages as well as daily, weather-dependent 

voltage fluctuations. Nearly all of the utilities interviewed mentioned the potential for advanced 

inverter power electronics to defer capital investments in the distribution system, as advanced 

inverters can actively regulate voltage on a distribution feeder in lieu of other devices. This can 

mitigate PV-induced voltage impacts and obviate the need for some, or all, of the traditional 

voltage-control equipment (Varma, Das, and Vanderheide 2011). Additionally, a subset of 

utilities interviewed expressed an interest in validating whether DGPV with advanced inverters 

can reduce transmission-level capital investments. As Denholm et al. (2014) observe, for 

instance, at the transmission level,

DGPV with advanced inverters can reduce the quantity of reactive power required 

from generators. This in turn allows generators to run at a higher (real) power 

output level, reduces transmission losses, and can increase the (real) power 

capacity of transmission lines by reducing the current flow from reactive power 

oscillations.

4 Advanced Inverter Deployment Challenges and 

Emerging Solutions

Despite responses—from the 2015 SEPA survey and our interviews—indicating a strong utility 

interest in advanced inverters, few utilities have deployed or required the deployment of such

inverters to date. Our results reveal several common themes related to the challenges of 

deploying advanced inverters, which help explain this discrepancy between interest and 

deployment:

• Involvement in ongoing, multi-party engagement

• Inability of standards to keep pace with technological advances

• Need for new communications infrastructure and protocols

• Lack of compensation mechanisms for ancillary services.

This section discusses interview responses related to these challenges, including emerging 

solutions. For the latter three challenges—which participants identified as the most important—

we provide additional context derived from other sources (e.g., IEEE, UL, CPUC).
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4.1 Involvement in Ongoing, Multi-party Engagement

Some utilities described their approach to implementing advanced inverters as system-wide, and

another described a “hot spot” approach that targets substations where the functional benefits 

would be greatest. All participants expressed a need to work directly with stakeholders—

including inverter manufacturers, regulators, standards committees, solar developers, and PV 

customers—to implement the programs. Utility participants said, for example, that the role of 

regulatory commissions and standards working groups is to specify the permissible inverter 

functions that utilities can employ, and that manufacturers are responsible for producing 

equipment that complies with the standards and with utility specifications. Participants also 

emphasized the importance of clearly communicating with the solar industry and end users to 

ensure compliance with changes to interconnection rules allowing for advanced inverter 

functionality. Additionally, because the market for advanced inverters is relatively new, one 

participant expected consolidation in the inverter sector as companies are acquired, merge, or 

fold; this could jeopardize long-term consumer needs for warranty claims, spare parts, and 

monitoring services.

4.2 Inability of Standards to Keep Pace with Technological Advances

Utilities interviewed were anticipating the final versions of codes and standards that currently are 

being revised. Utility expectations for advanced inverter functionality differ, and multiple 

participants stated that no advanced inverter is available as “off-the-shelf” technology. Rather, 

utilities must partner with inverter manufacturers to define advanced inverter function set points

for each utility’s unique specifications. Participants expressed the hope that the updated 

standards will produce common functional solutions for the broader market.

Interconnecting DER to the grid requires compliance with a number of standards governing 

safety, reliability, and electrical performance. Three main standards have a direct impact on the 

ability of utilities and solar companies to deploy and operate advanced inverters in the United 

States: the National Electrical Code (NEC), Underwriters Laboratories (UL) 1741, and IEEE 

1547 (see Appendix D for more detail on these standards). The NEC addresses the safe 

installation of electrical wiring and equipment. The UL 1741 standard is an equipment safety 

standard that is used to certify that a specific piece of equipment as safe for a given use. By 

contrast, IEEE 1547 is an interconnection standard that regulates how an inverter may impact

electrical conditions at the point of common coupling (PCC) when interconnected to an electrical 

system. Because the existing versions of UL 1741 and IEEE 1547 (IEEE 1547-2003) were 

written prior to the development of advanced inverters, those devices cannot be certified as safe, 

nor can they perform their advanced functions when interconnected to the grid.1

Currently, UL 1741 and IEEE 1547-2003 are being revised to accommodate the expanded 

functionality of advanced inverters. The recent IEEE 1547a-2014 standard was a first step in this 

 

1 In 2014, an amendment to IEEE 1547-2003, titled IEEE 1547a-2014, removed the prohibition on distributed 

generation actively regulating voltage at the PCC and allowed grid operators to coordinate active voltage control 

with DER operators, if desired. Additionally, IEEE 1547a-2014 extends the default clearing times for distributed 

resources during voltage or frequency anomalies, and allows grid and DER operators to specify even more lenient 

ride-through settings collaboratively. This amendment is designed to increase the contribution of distributed 

generation to overall grid reliability.
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process, as it establishes expanded ride-through settings and permits active voltage control at the 

PCC if coordinated between DER owners and grid operators. However, other advanced inverter 

capabilities still cannot be UL certified for many U.S. uses until the changes to both standards 

are finalized—which is delaying advanced inverter deployment. This delay is driven in part by 

widespread U.S. adoption of the two standards; of the 44 states that have mandatory, statewide 

interconnection standards, Texas is the only one that does not explicitly refer to either UL 1741 

or IEEE 1547. Even in states without statewide interconnection standards, many utilities have 

incorporated both the UL and IEEE standards into their own interconnection procedures to 

ensure safety and reliability. Figure 2 illustrates how other key regulations for distributed 

generation rely on these two standards, and how these dependencies have impacted deployment 

of advanced inverters. The following subsections discuss the status of the revision processes for 

these critical standards. 

Safety 

Certification 

UL 1741 does not have 

a testing procedure for 

advanced inverters

Without a developed 

testing program under 

UL 1741, advanced 

inverters cannot 

achieve UL listing

Installations using 

advanced inverters 

which are not UL-listed 

cannot comply with the 

National Electrical Code

Installations which do 

not comply with the 

National Electrical Code 

will violate local 

building codes 

Interconnection 

Performance

IEEE 1547-2003 does 

not allow inverters to 

perform "advanced" 

functions beyond those 

in IEEE 1547a-2014

In most states, an 

inverter which violates 

IEEE 1547-2003 does 

not meet state 

interconnection 

standards

Inverter deployments 

which do not meet state 

standards will not pass 

utility interconnection 

processes

Figure 2. How regulations for distributed generation depend on IEEE 1547 and UL 1741.

4.2.1 California Rule 21 and the Smart Inverter Working Group

Much of the impetus for the ongoing revisions to UL1741 and IEEE 1547 has come from 

California, which boasts the largest U.S. DGPV market. In January 2013, regulators at the CPUC 

and California Energy Commission

(CEC) jointly convened the Smart 

Inverter Working Group (SIWG). This 

diverse group—which includes utilities, 

solar installers, equipment 

manufacturers, and other stakeholders—

was tasked with recommending 

modifications to California’s Rule 21, 

the tariff under which the state’s major 

investor-owned utilities are required to 

interconnect generation facilities to the 

distribution system. 

Neither UL nor IEEE had initiated 

revisions to enable advanced inverter 

functionality, and by 2013 the CPUC, 

CEC, and SIWG were prepared to 

develop their own standards (if 

Identifying Locational Benefits of Advanced Inverters 

through Distribution Resource Planning—In addition 

to the SIWG's effort to revise Rule 21, California is 

also addressing advanced inverter use through CA AB 

327, under which each of the three investor-owned 

utilities are required to produce distribution resource 

plans (DRPs). These DRPs will define locational 

benefits of—and identify optimal locations for—DER 

systems. Later in the DRP process, utilities include the 

use of advanced inverter functions (e.g., volt-VAR

control) to ensure safe and reliable distribution 

operations. Although efforts to incorporate advanced 

inverters into broader distribution management and 

planning are in their infancy, there is long-term 

potential for these assets to play a crucial role. 
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necessary) to allow the use of advanced inverters. California’s urgency to update the standards 

was driven by its rapidly proliferating DGPV market and the associated grid-integration 

challenges that must be addressed to ensure reliability, as was demonstrated in high-penetration 

regions such as Hawaii and Germany. Further, it was becoming clear that standards originally 

designed to maintain grid reliability actually might threaten it. The requirement for DERs to trip 

offline during voltage or frequency anomalies, for example, has changed quickly from a 

necessary precaution to a serious hazard to overall system stability, as evidenced by system 

events in Germany and Italy. 

To enable advanced inverters to perform beneficial grid functions rapidly, the SIWG proposed a 

three-phase process.

• Phase 1 would identify seven high-value functions that advanced inverters could perform 

autonomously based on static set-points or predefined operational curves. These were 

seen as “the biggest bang for the buck,” increasing overall system stability without the 

need for expensive communications infrastructure.

• Phase 2 would develop communications standards for the interactions between utilities, 

DER aggregators, and individual DER facilities. This step required a technology-neutral 

approach that would also facilitate the deployment and engagement of non-photovoltaic

DERs such as storage, demand response, smart home systems, and electric vehicles.

• Phase 3 would identify additional advanced functions—beyond the seven identified in 

Phase 1—which also might be required of interconnected facilities through Rule 21. 

These additional functions could be either autonomous or require communications 

infrastructure as outlined in the Phase 2 standards.

On December 18, 2014, the CPUC approved the Phase 1 recommendations of the SIWG to 

require the seven additional autonomous functions under Rule 21. The three main California 

investor-owned utilities were given 30 days to modify and resubmit their Rule 21 tariffs to 

reflect these changes. Under the CPUC’s ruling, the effective date of these changes was set as the 

later of either December 31, 2015, or 12 months after UL 1741 is updated to accommodate 

SIWG’s Phase 1 recommendations. Additionally, the most recent draft of SIWG Phase 2 

recommendations on communications standards was issued on February 28, 2015, but it has not

yet been taken up by the CPUC. Phase 3 discussions of additional advanced functions to be 

added under Rule 21 are still ongoing as of September 2015.

4.2.2 UL 1741 SA

Underwriters Laboratories currently is creating a supplement to its 1741 standard, UL 1741 SA, 

titled “Supplement for Grid Support Utility Interactive Inverters.” The supplement encompasses

advanced inverter functionalities required in California as a result of the Smart Inverter Working 

Group. This expansion will require the development of new test plans and acceptable behavior 

for devices when they are performing advanced functions. Prior to public release, a preliminary 

review and comment period for the standard must be completed; the standard then must be

passed by the Standards Technical Panel. Underwriters Laboratories expects the UL 1741 SA 

supplement encompassing enhanced functionality to be published in fall of 2015; it had not yet 

been released as of September 2015.
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The publication of the expanded UL 1741, however, will not immediately permit the installation 

of advanced inverters. Rather, manufacturers must certify their equipment under the updated 

standard by completing UL’s testing process. For a device that already has been certified under 

the existing UL 1741 and simply has received software updates to enable advanced functions, 

expanded certification could be obtained in as little as one to two months. Inverters requiring 

substantial hardware changes or those featuring entirely new designs to offer advanced 

functionality, however, could take as long as four months to certify.

As noted, the final ruling on the SIWG’s Phase 1 recommendations to the CPUC makes an 

explicit linkage between the publication of UL 1741 SA standard and the effective date of the 

Rule 21 updates. This could trigger a rush among manufacturers to certify their equipment ahead 

of the one-year deadline rather than risk being shut out of the large California market. 

Underwriters Laboratories has noted the possibility of an increase in applications for certification 

following the release of the new standard, and it believes it is well positioned to meet the 

certification needs of manufacturers in advance of the one-year Rule 21 deadline. 

4.2.3 IEEE 1547 Full Revision

The IEEE 1547 Full Revision process establishes a framework under which inverters are 

permitted to perform various advanced functions. The standard strictly governs the behavior of 

devices—not limited to inverters—at the PCC. The revision was spurred in part by the SIWG’s 

recommended Rule 21 updates. In the past, Rule 21 relied on IEEE 1547 to specify acceptable 

DER behavior at the PCC, but some of the approved Phase 1 functions go beyond those 

permitted in previous revisions of IEEE 1547.

The ongoing revision is intended to be comprehensive, with all clauses subject to review. It is 

focused on enabling greater penetration of DERs including DGPV equipped with advanced 

inverters. Under a high-penetration scenario in which DERs comprise an ever-larger share of 

energy supplied to the grid, the required behaviors of those resources also must change, shifting 

from a “do no harm” role to one of active grid support. For example, frequency and voltage ridethrough specifications in the updated IEEE 1547 might define larger regions under which 

devices must remain connected, in contrast to the must-trip zones under the existing IEEE 1547-

2003 and 1547a-2014. Discussions during the revision process have included voltage regulation 

and power factor controls—two key advanced inverter capabilities that could increase the ability 

of specific feeders to host more DERs. Balloting for the full IEEE 1547 revision has been 

forecast for fall 2016 (Sun 2015).

4.3 Need for New Communications Infrastructure and Protocols

All interview participants repeatedly highlighted the need for communications infrastructure and 

protocols to make inverters an integrated grid asset that is interoperable with other infrastructure.

This includes the ability of grid operators to work with devices from various manufacturers as 

well as existing distribution equipment, metering and billing systems, and other utility systems. 

Participants described the integration of advanced inverters with distribution management 

systems and DER management systems as long-term goals, but they cautioned that these changes 

would require significantly more work before becoming operational.

Utilities also described a tradeoff among communications-infrastructure options: more 

bandwidth enables greater real-time functionality and control but at a greater implementation 
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cost. To put this infrastructure into service, communications standards must be implemented to 

ensure compatibility with existing communications networks and other DER needs. Some utility 

participants described plans to install more robust communications capabilities on inverters in 

specific areas and to rely on autonomous functions or more limited bandwidth in others. 

Advanced inverters could autonomously provide some enhanced functionality based on static 

set-points, which can be defined at installation and then can later be adjusted by inverter

technicians. These autonomous functions do not require communications connectivity or 

operator dispatch. Other functions require more frequent (approaching real-time) 

communications to realize their full benefit. In our interviews, several utilities described the 

significant challenges inherent in establishing the communications infrastructure to interact with 

advanced inverters. Nevertheless, these same utilities unanimously asserted that the effort and 

cost of this infrastructure would be worth the incremental benefit provided by communicationsreliant functions. 

The SIWG update of California’s Rule 21 indicates the significant complexity involved in 

developing standards for advanced inverter communications infrastructure. The SIWG 

deliberately avoided all discussion of communications and communications-dependent functions 

in Phase 1, instead focusing on a small set of high-value functions that could be performed 

autonomously. Discussions of communications-system design and standards were entirely 

deferred to Phase 2, from which the SIWG delivered its recommendations to the CPUC in 

February 2015. Participants waited until Phase 3, which began in early 2015, to begin discussing 

advanced functions that rely on communications for successful operation. This process bypassed 

the technical complexity and consensus-building challenges of Phase 2 and Phase 3 to achieve 

the benefits of Phase 1 functions as quickly as possible.

The following subsections discuss the relationship between advanced inverter functionality and 

communications, as well as the elements of a communications infrastructure.

4.3.1 Relationship Between Advanced Functionality and Communications

The Phase 3 work of the SIWG highlights the robust capabilities of communications-enabled 

advanced inverters. Table 2 (below) highlights which inverter functions generally are considered 

autonomous and which require some level of communications connectivity. Autonomous 

functions that generally rely on static parameters also can benefit from adding a communications 

system that enables easier and more frequent adjustment of those parameters.
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Table 2. Autonomous Versus Non-Autonomous Inverter Functions

Description Functions

Associated 

Proceedings and 

Standards

Autonomous – No 

communications 

architecture 

needed

– Behavior 

controlled by 

inverter operating 

parameters

– Parameters 

defined at system 

commissioning or 

later

– Parameters can 

be adjusted, 

behavior activated 

or deactivated at 

later date via 

remote or on-site 

changes

Low- / High-voltage ride-through SIWG 

Phase 1

IEEE 

1547a2014 Low- / High-frequency ride-through

Volt-var control

(via dynamic reactive power injection)

Anti-islanding

Ramp-rate controls

(for default/emergency conditions)

Provide reactive power

(via fixed power factor)

Reconnect via “soft-start”

Frequency-watt SIWG 

Phase 3 Voltage-watt

Dynamic current support

Smooth frequency deviations

NonAutonomous – Communications 

and control 

infrastructure 

required

– Direct control of 

inverter behavior 

– Control from 

remote operator 

commands or 

feedback, based 

on conditions at 

point of common 

coupling

Command DER to 

connect/disconnect

SIWG 

Phase 3 

Limit real power

Set real power

Provide black-start capability

Respond to real power pricing signals

Participate in automatic generator 

control (AGC)

Provide spinning reserves or bid into 

market

Update static set points for 

autonomous functions

(fixed power factor, volt-var curves,

voltage ride-through, frequency ridethrough)

4.3.2 Elements of a Communications Infrastructure

To link with advanced inverters in the field, utilities must design a communications 

infrastructure by choosing from among multiple options at each link in the communications 

chain. Many protocols and transfer media exist, each offering different benefits and drawbacks in 

terms of cost, security, interoperability with existing systems, and flexibility for incorporating 

future applications. An exhaustive comparison of these alternatives is beyond the scope of this 
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report, but Table 3 shows some of the options utilities have for each element of their 

communications infrastructure; SIWG-recommended elements are highlighted in bold. Brief 

descriptions of each layer and the listed examples are provided in Appendix E.

Table 3. Utility Options for Communications Infrastructure

Communications Layer Layer Function Examples of Layer

Data/information model

Provide data frameworks to 

describe electronic equipment 

states and functions

IEC 61850

OpenADR

Common Information Model

Utility/“application” protocol Standardize data exchange 

between utility assets and DERs

SEP 2.0 (IEEE 2030.5)

DNP3 (IEEE 1815)

Communications/“transport” protocol Enable data transfer over physical 

media Internet Protocol: TCP/IP

Communications method/media

Provide the infrastructure for data 

transfer between field assets and 

control centers

Utility Private WAN

Cellular GPRS

Public Internet

AMI Network

Telecom Provider

Facility/DER/“application” protocol Provide means of controlling one or 

more DERs at a single premises

SEP 2.0 (IEEE 2030.5)

ModBus

4.4 Lack of Compensation Mechanisms for Ancillary Services

Utility participants described numerous functional benefits from advanced inverters, such as 

power-quality enhancements and curtailment—known collectively as ancillary services. Today, 

however, inverters almost always belong to PV customers and PV developers. Interview

participants acknowledged that another challenge to realizing the benefits of advanced inverters 

is the lack of widely used mechanisms to compensate PV owners for ancillary services.

Several utilities are launching pilot projects to determine the technical capabilities of advanced 

inverters and the monetary value they could provide. Overall, participants expressed that the 

monetary value of advanced inverter functionality is currently realized much more easily if the 

utility owns the PV array, inverter, and all associated equipment. Without a compensation 

framework to transfer financial benefits between equipment owners, the greatest savings are

achieved by letting all benefits accrue to the utility. Utility-owned DGPV—such as that approved 

for deployment in Tucson Electric Power Company (TEP) and Arizona Public Service (APS)

territories (see Section 5)—bypasses the compensation and rate-making challenges inherent to 

controlling third-party-owned systems, and enables quicker experimentation and results.
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Non-utility-owned PV presently dominates the DER market, and seems poised to do so in the 

foreseeable future. Therefore, enabling utilities to access the benefits of advanced functionality

and compensating system owners appropriately will become an increasingly pressing issue. New 

York’s K-Solar program exemplifies what happens today with the lack of a consistent 

compensation framework. During our interview with the PV owner, New York Power Authority, 

staff stated that they had been willing to work with local utilities to enable advanced inverter 

functionality for their school-based solar systems, but that this plan was ultimately abandoned 

because of the lack of a standard compensation scheme.

At the transmission level, compensation mechanisms exist for ancillary services provided by 

advanced inverters. PJM, for example, provides for a “capability payment” under the tariff 

Schedule 2 for reactive power and voltage control. It is provided as a base cost of service, but 

PJM also pays reactive services providers the difference between the locational marginal price 

and the seller’s offer price for energy, depending on whether the real power out of the provider’s 

resource is reduced or increased (PJM Tariff). 

Compensation mechanisms for ancillary services are especially important when a generating 

asset must forego some real power output—and associated revenue—to supply reactive power

instead. Although it is possible for an inverter to supply VARs in addition to maximum real 

power output, an oversized inverter is required. The larger inverter costs more to install, and if 

the owner is not compensated for the additional ancillary services, then the more costly 

investment cannot be justified.

In contrast, as part of the interconnection agreement for distribution-level commercial PV, 

utilities commonly stipulate that the PV asset must operate off unity power factor as a condition 

for interconnection approval. For projects installed at the end of a distribution feeder (as at many

industrial parks), for example, the PV owner often is asked to operate at 0.95 leading power 

factor and to inject VARs back to the distribution system to compensate for inductive loads. 

Although using inverter settings this way can avoid costly infrastructure upgrades for the utility, 

the PV owner is not compensated for the loss of real power production or for the grid-support 

functions provided. Additionally, the utility often reserves the right to mandate a power factor 

adjustment at any point in the PV system’s operational lifetime. Financiers typically accept this 

stipulation as boilerplate interconnection-agreement language, but it can potentially increase 

financial risk over the 20- to 25-year life of a PV asset.

5 Arizona’s Deployment Strategies and Solution 

Pathways

As part of our interview process, APS and TEP agreed to provide additional information to 

illustrate their advanced inverter deployment processes. In December 2014, both utilities 

received approval from the Arizona Corporation Commission to offer rooftop PV installation 

programs to their customers (AZCC 2014a, AZCC 2014b). In return for financial 

compensation—a monthly “rooftop lease” payment from APS or a long-term contract for a fixed 

bill from TEP—the utilities will finance, own, and operate PV systems on residential customer 

rooftops. Under this arrangement, the systems will interconnect to the distribution system on the 

utility side of the meter. In their program filings with the Arizona Corporation Commission

(AZCC), staff at both utilities cited the opportunity to own and control a distributed fleet of 
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advanced inverters as one of the key benefits of their respective programs (APS 2014, AZCC 

2014c).

A primary program objective for both utilities is to verify the capabilities and potential benefits 

of advanced inverters. One of the purported benefits of advanced inverters coupled with DGPV 

systems is the ability to defer otherwise-necessary system upgrades or maintenance by reducing 

net loads or stabilizing voltage. Both utilities believe that their programs will provide sufficient 

data for assessing whether advanced inverters actually provide such a benefit. Furthermore, both 

say that this data collection and performance verification will be much easier when all physical 

assets in the operational chain are utility owned. Specifically, they think that the logistics of 

communications infrastructure and issues of operational access and adjustments will be 

streamlined, and that examining the complex issues of compensating customer- or third-partyowned systems for advanced capabilities can be deferred until the value of these capabilities is 

better understood.

Both APS and TEP expressed interest in the ability of advanced inverters to mitigate local 

stability issues and support wider-scale system reliability via expanded voltage and frequency 

ride-through settings. Arizona Public Service highlighted two specific use cases for advanced 

inverters in its rooftop PV program. The first is deploying utility DGPV on load-stressed feeders, 

where peak loads approach the maximum conductor capacity. In this case, APS will study 

whether introducing utility-owned DGPV could reliably deliver peak-load reductions while 

reducing the cycling of tap-changing transformers serving those segments. The second use case, 

somewhat counterintuitively, involves feeders already experiencing high penetration of 

customer- or third-party-owned PV. In these situations, adding utility-owned PV with advanced 

inverters might help mitigate voltage fluctuations along the feeder caused by existing DGPV, 

thus improving power quality, reducing the risk of voltage violations, and reducing cycling of 

distribution equipment.

Each utility described challenges related to the lack of market readiness of advanced inverter 

technologies. Because of the current unavailability of UL certification for advanced inverter 

functionality, one APS engineer remarked that he “might not even be able to stick [an advanced 

inverter] on a house.” The TEP noted similar challenges and also that it has been forced to work 

hand-in-hand with manufacturers to enable the “latent” advanced capabilities of the inverters, 

because these functions are not available “off the shelf.” This collaboration will benefit both 

parties in the long run, as TEP plans to provide real-world operational data to its partner 

manufacturers to improve their product offerings.

Another major challenge to deploying utility-controlled advanced inverters is establishing realworld, real-time communications infrastructure. As Marc Romito of APS noted, “real-time” in 

this scenario could describe a response time of anywhere from two seconds to five minutes. The 

path each utility chooses for communications will be influenced by its existing information 

technology assets in the field. APS developed an advanced metering infrastructure (AMI) 

network, and TEP implemented an automatic meter reading (AMR) system which allows the 

remote collection of customer energy use data but has fewer data-collection and transfer 

capabilities than the APS system. APS suggested that it might leverage its existing AMI system 

for communications to and from the advanced inverters it controls. TEP is piloting a new 

cellular-based control scheme across a dozen locations, though it plans to eventually transition to 
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a proprietary wireless network for its full program deployment. Both utilities described real-time 

inverter communications as a difficult but worthwhile logistical effort, because it will unlock 

high-value advanced capabilities such as volt-VAR control and real-power curtailment. Both also 

noted that—because of the strong seasonality of load factors and capacity factors in Arizona—

communications infrastructure should enable the remote adjustment of operating parameters for 

otherwise-autonomous functions. This capability will reduce operations and maintenance costs 

by saving labor hours, travel for site visits, and other fieldwork that would otherwise be required 

for onsite adjustments of these parameters.

Lastly, both utilities indicated that advanced inverters are not a standalone solution to 

distribution issues but rather an important element of future distribution system management. 

Integrating the capabilities of advanced inverters will be important for both utilities as new 

DERs—such as energy storage, electric vehicles, demand-side management programs, and 

increased rooftop PV deployment—combine to create a more variable and challenging 

environment for distribution engineers in the future.

6 Conclusion

Our research elaborates the perspectives on advanced inverters from seven utilities, a regional 

transmission operator, an inverter manufacturer, a leading solar developer, and a consortium for 

grid codes and standards. These participants identified several benefits they expect from 

advanced inverters as well as several challenges to implementing the technology.

• Benefits

o Improvement in system reliability and power quality

o Increase in distribution-network visibility through sensor data

o Potential deferral of utility grid capital investments.

• Challenges

o Involvement in ongoing, multi-party engagement

o Inability of standards to keep pace with technological advances

o Need for new communications infrastructure and protocols

o Lack of compensation mechanisms for ancillary services.

Our report provides additional context on the latter three challenges, which participants 

identified as the most important. Following is a brief discussion of these three challenges, along 

with emerging solutions.

The updating of electric-system standards generally proceeds slowly and deliberately, and the 

current versions of two particular standards—UL 1741 (addressing equipment safety) and IEEE 

1547 (addressing interconnection)—are delaying use of advanced inverters nationwide. 

California’s urgent need to accelerate advanced inverter deployment, however, is helping to

stimulate sweeping revisions of the standards. We anticipate that these pending updates not only 

will ensure the safe incorporation of new functions of advanced inverters into individual systems 

and the grid, but also will enable the inverters to provide active grid support. Additionally, the 

updates will likely promote progress toward mass-produced advanced inverters with common 
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.This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

functionality, satisfying the desire we heard from interview participants for “off–the-shelf” 

products. In any case, the updates should remove the standards-related barriers to advanced 

inverter deployment.

Another critical challenge is establishing the communications capabilities needed to realize the 

grid-support potential of advanced inverters. Many communications options are available, and as 

the capabilities of the options increase so does their cost. To balance the cost-benefit tradeoff, 

some of the utilities we interviewed are planning hybrid approaches that relegate advanced 

inverters in certain areas to autonomous or low-bandwidth operation, and enable robust 

connectivity on inverters in other areas. Overall, our utility participants agreed that the benefits 

of establishing communications infrastructure for advanced inverters outweigh the associated 

complexity and costs.

Lastly, the lack of mechanisms to compensate non-utility PV owners for providing ancillary 

services presents a challenge to realizing the full potential of advanced inverters. Some utilities, 

including APS and TEP, are experimenting with utility ownership and control of PV systems 

mounted on customers’ rooftops. Under this framework, utilities can streamline operational 

logistics and avoid complex financial compensation issues, and can assess the value of the 

services they receive from the advanced inverter–enabled systems. Results from such projects 

then can inform the development of future mechanisms for compensating non-utility PV owners. 

This is important because non-utility ownership seems likely to remain the dominant form of 

distributed PV deployment in the foreseeable future.

The amount of experience and data from advanced inverter use will increase dramatically over 

the next several years as the new electric-system standards come into effect, pilot-program 

results become available, and many more advanced inverters are deployed. Will the anticipated 

benefits materialize? How much will they be worth? How will the value be distributed among 

multiple stakeholders? What role will advanced inverters play in an electric system that features 

increasing amounts of DERs, including energy storage, electric vehicles, demand-side 

management, and rooftop PV? Such questions, along with the emerging data, will present many 

avenues for additional research aimed at quantifying the benefits and challenges associated with 

advanced inverters.
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Appendix A. SEPA’s Annual Solar Market Survey 

Instrument 2015

7.) What solar activities do you expect your utility to continue or implement in 2015? 

(Check all that apply)

Activities Currently offer/ 

Implementing

Planning/

Considering/ 

Researching

Not 

Planning/ 

No Interest

Solar Incentive for Customers (e.g., 

rebates, performance)

Restructuring of rates or charges to 

manage net metering revenue impacts

Utility-managed community solar programs

Third-party managed community solar 

programs

Value of solar tariff

Feed-in-tariff

Renewable/green programs for key 

account customers (customers with 

highest energy demand [e.g. commercial, 

industrial, educational, etc.]) 

Utility integrated resource plan indicating 

solar as a least cost resource

Utility-scale solar procurement (ownership 

and/or RFPs)

Locational deployment (influencing the 

location of customer-owned solar energy 

facilities)

On-bill financing

Advanced inverter functionality activities 

(e.g., customer requirements, R&D)

Energy storage (excluding pumped hydro)

Solar Energy Production Forecasting 

(short-term, operational, employment of 

technology and algorithms using weather 

data)
21

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

Appendix B. Utilities Implementing or Exploring 

Advanced Inverters (from SEPA 2015 Survey)

Utilities that currently are implementing advanced inverter functionality:

• Arizona Public Service (AZ)

• Atlantic City Electric (NJ)

• Avista Utilities (WA)

• Delmarva Power (DE, MD)

• Hawaiian Electric Company, Inc. (HI)

• Kauai Island Utility Cooperative (HI)

• National Grid Massachusetts Electric Co. (MA)

• Niagara Mohawk Power Corp. (NY)

• Pacific Gas & Electric Company (CA)

• Pepco (Potomac Electric Power) (DC, MD)

• Sacramento Municipal Utility District (CA)

• San Diego Gas & Electric Company (CA)

• Southern California Edison (CA)

• The Narragansett Electric Co. (RI)

• Tucson Electric Power Company (AZ).

Utilities planning, researching, or considering advanced inverter functionality:

• Anaheim Public Utilities (CA)

• Austin Energy (TX)

• Central Hudson Gas & Electric Corporation (NY)

• Clark Public Utilities (WA)

• Connecticut Light and Power Company (CT)

• Consolidated Edison Company of New York (NY)

• CoServ Electric (TX)

• CPS Energy (TX)

• Dominion Virginia Power (VA)

• Duke Carolinas (NC, SC)

• Duke Energy Progress (NC, SC)

• Duke Indiana (IN)

• El Paso Electric Co. (NM, TX)

• Georgia Power Company (GA)

• Holy Cross Energy (CO)

• Indianapolis Power & Light Company (IN)

• Interstate Power and Light Co. (IA)

• Kit Carson Electric Cooperative (NM)

• Long Island Power Authority (NY)

• Los Angeles Department of Water and Power (CA)
22

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

• Minnesota Power (MN)

• Nebraska Public Power District (NE)

• New York Power Authority (NY)

• NV Energy (NV)

• Omaha Public Power District (NE)

• Orange and Rockland (NY)

• Pacific Power (CA, OR, WA)

• Pike County Light & Power Co. (PA)

• Platte River Power Authority (CO)

• Portland General Electric (OR)

• Public Service Electric & Gas Company (NJ)

• Public Service of New Hampshire (NH)

• Puget Sound Energy (WA)

• Rockland Electric Company (NJ)

• Rocky Mountain Power (ID, UT, WY)

• Roseville Electric (CA)

• San Miguel Power Association (CO)

• South Carolina Electric & Gas Co. (SC)

• UNS Electric, Inc. (AZ)

• Vineland Municipal Electric Utility (NJ)

• Westar Energy, Inc. (KS)

• Wisconsin Power and Light Co. (WI)

• Xcel MN—Northern States Power (MN).
23

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

Appendix C. NREL-SEPA Interview Questions Used for 

Data Collection

General Utility Information

Utility and Contact Information

Please answer the following questions about the utility you represent.

Utility Name: _________________________________________________

Primary Contact First and Last Name: _________________________________________________

Primary Contact Email Address: _________________________________________________

Primary Contact Phone: _________________________________________________

1) How does your utility perceive smart inverter technology, its applications, challenges 

and opportunities?

2) What kinds of studies and analysis are being conducted to better understand the 

technology?

3) Do you require smart inverters for interconnection?

[ ] Yes

[ ] No

[ ] Details? (write in): _________________________________________________

Is your utility considering requiring them?

[ ] Yes

[ ] No

[ ] Details? (write in): _________________________________________________
24

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

4) Is your utility considering/developing protocols (safety, interconnection, deployment 

strategies) specific to smart inverters?

[ ] Yes

[ ] No

[ ] Not sure

Please describe the protocols being considered/planned.

5) Is your utility interested in participating in the ancillary markets for frequency and 

voltage regulation using smart inverters? 

[ ] Yes

[ ] No

[ ] Details? (write in): _________________________________________________

How is your utility planning to participate in the ancillary markets for frequency and 

voltage regulation using smart inverters?

6) Does your utility see a benefit from third parties using smart inverters? Please 

describe the pros and cons of third parties using these devices.

7) Who has legal authority for operational setting changes of customer-sited advanced 

inverters? Who should?

8) Is your utility considering ownership of smart inverters?

( ) Yes

( ) No

( ) Not sure
25

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

What considerations are being given to ownership of advanced inverters?

9) What is the biggest grid integration challenge you would hope to address with 

advanced inverter functionality?

10) What types of smart inverter applications are being used/considered?
26

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

Appendix D. Overview of Advanced Inverter

Deployment Standards

Standard Overview

NEC

The NEC is a standards document developed by the National Fire Protection Association that 

addresses the safe installation of electrical wiring and equipment. Adoption of the NEC varies 

by state, with at least five states implementing each of the 2008, 2011, and 2014 editions of 

the code as of the writing of this report. All 50 states have adopted the NEC in some form: 

most states have adopted the NEC on a statewide basis, though at least 10 grant some 

discretion for adoption to local jurisdictions (NEMA 2015). Three sections of the NEC require 

that inverters be UL listed and identified for their intended use (UL 2012): 

NEC Section 690.4 (B)—Solar Photovoltaic (PV) Systems;

NEC Section 690.35(G)—Ungrounded Photovoltaic Power Systems; and 

NEC Section 705.4—Interconnected Electric Power Production Sources.

UL 1741

Inverter manufacturers can fulfill the “listing” requirement of the NEC sections above by 

certifying their equipment under standards issued by UL, a for-profit standards development, 

testing, and certification corporation. The relevant standard for inverters is UL 1741, 

“Inverters, Converters, Controllers and Interconnection System Equipment for Use with 

Distributed Energy Resources.” This standard sets all manner of requirements for inverters: 

construction specifications for inverter enclosures, external connections, and internal 

hardware; protections against injury to persons; external warnings and informational 

markings; and electric-output characteristics. In the area of electric performance, UL 1741

defines testing procedures and acceptable behaviors under a wide range of abnormal 

conditions, including short circuits, direct current input miswiring, restricted ventilation, high 

temperatures, and voltage spikes. Where the standard discusses the interaction of inverters 

with a utility electric system, UL 1741 explicitly requires conformance with IEEE 1547-2003 

and its companion testing procedure, IEEE 1547.1 (UL 2010).

IEEE 

1547

Approved in 2003 and reaffirmed in 2008, IEEE 1547-2003 provides technical specifications 

governing the interconnection of a DER to the electrical grid. The standard applies to DERs 

with an aggregate rating of 10 megavolt amperes (MVA) or less at the PCC2 and 

interconnected at primary or secondary distribution voltages. The specifications of IEEE 

1547-2003 define acceptable (or unacceptable) behaviors of the DERs in terms of their effect 

on electrical conditions at the PCC. The following provides a partial list of these topics and 

the relevant section of the standard.

Voltage regulation (4.1.1)

Response to grid faults (4.2.1)

Voltage (4.2.3)

Frequency (4.2.4)

Unintentional islanding (4.4.1)

In addition to defining behaviors, IEEE 1547-2003 outlines a testing and evaluation 

procedure to certify that the interconnection of a DER will meet the required conditions 

defined above. 

 

2 The PCC represents the point at which the onsite, local electric power system (local EPS), which may contain one or more 

distributed resources, connects to the wider grid, or area electric power system (area EPS).
28

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

Appendix E. Description of Communication Layer 

Options

Communications Layer Purpose Examples Description

Data/

information

model

Data and information 

models provide the 

structure for describing 

devices, their 

functions, and other 

operating parameters 

of electrical system 

operations.

IEC 61850

IEC 61850 was 

originally designed for 

communication 

between devices 

within a substation, 

but has since been 

expanded to 

distributed energy 

resources, hydro 

power and wind 

power (Summary 

2010).

OpenADR

OpenADR provides a 

data model strictly 

tailored to demand 

response devices and 

functions.

Common Information Model

(IEC 61970, IEC 61968)

The Common 

Information Model is 

a data construct to 

describe the physical 

infrastructure of the 

transmission and 

distribution systems 

as well as the flow of 

power on these 

elements (Simmins 

2011).

Utility/

“application”

protocol

Utility or “application” 

protocols allow for 

communication 

between the local 

distribution utility and a 

distributed energy 

resource (or an 

aggregation of them).

SEP 2.0

(IEEE 2030.5)

SEP 2.0, released in 

2013, was explicitly 

designed for home 

automation and 

distributed energy 

applications by a 

consortium of 

communications 

technology 

organizations (IEEE

Adoption 2013).

DNP3

(IEEE 1815)

DNP3 was originally 

designed for 

communication 

between utility master 

control stations and 

assets in the field in 

the early 1990s (DNP 

Users Group 2005).
29

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

Communications Layer Purpose Examples Description

Communications/

“transport” protocol

A communications 

protocol layer is 

necessary to specify 

how data should be 

packetized, sent, 

routed, and received.

TCP/IP

(Internet model)

By far the most widely 

used communications 

layer is the 

combination of 

Transmission Control 

Protocol (TCP) and 

Internet Protocol (IP), 

which are most well 

known as the basis of 

the modern Internet. 

Communications

method/media

Communications 

methods and media 

describe means for 

transmitting 

communicable data 

between devices. 

There are many 

options for this layer 

and the chosen 

method will often be 

determined by a joint 

consideration of cost, 

functionality, and 

security.

Utility Private WAN

Wide-area networks 

(WANs) span a broad 

geographic area. 

They often use 

leased 

communication 

channels, but utilities

can develop their own 

private networks for 

greater performance 

and security.

Cellular GPRS

General Packet Radio 

Service (GPRS) is a 

data service on 2G or 

3G mobile networks 

which uses the global 

system for mobile 

communications

(GSM).

Public Internet

Public Internet 

communications use

the same 

infrastructure which 

provides Internet 

service to homes and 

businesses.

AMI Network

AMI networks collect 

data from a fleet of 

smart meters.

Telecom Provider

Utilities can partner 

with telecom 

providers to create 

solutions which make 

use of wired or 

wireless networks.
30

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

Communications Layer Purpose Examples Description

Facility/DER

“application” protocol

Facility-level 

communication 

protocols enable 

communications 

between multiple 

devices on the same 

premises with one 

common 

communications 

connection to the 

associated utility 

system.

SEP 2.0

(IEEE 2030.5)

In addition to 

communications 

between a utility and 

a customer, SEP 2.0 

can also facilitate 

communications 

between devices at 

the same location.

ModBus

ModBus is a 

commonly used 

protocol for withinfacility 

communications. It 

was developed in the 

late 1970s to enable 

communications 

between electronic 

devices used in 

industrial processes 

(Modbus 2015).