Rolling Out SMARTINVERTERSASSESSING UTILITY STRATEGIES AND APPROACHES

Ryan EdgeResearch AnalystSolar Electric Power Association

Ben YorkSenior EngineerElectric Power Research Institute

Nadav EnbarPrincipal Project ManagerElectric Power Research Institute

ROLLING OUT SMART INVERTERS 2 SEPA AND EPRI

CONTENTSINTRODUCTION ............................................................................3

WHAT IS A SMART INVERTER? ......................................................4

LOOKING TO GERMANY FOR PERSPECTIVE .................................3

PROFILING SELECTED U.S. UTILITY ROLLOUT APPROACHES .......6

HAWAIIAN ELECTRIC COMPANIES .........................................7

ARIZONA PUBLIC SERVICE .....................................................8

PACIFIC GAS & ELECTRIC .......................................................9

SALT RIVER PROJECT ............................................................11

KEY FINDINGS ............................................................................12

CONCLUSION AND FUTURE CONSIDERATIONS .........................14

ACKNOWLEDGEMENTS ...............................................................14

ENDNOTES ..................................................................................15

ROLLING OUT SMART INVERTERS 3 SEPA AND EPRI

Rolling Out Smart Inverters

INTRODUCTIONThe widespread deployment of solar photovoltaics (PV) in the United States has spurred interest in new inverter technology with enhanced grid supportive functionality. These advanced inverters, also known as “smart” inverters, are primed for widespread commercial rollout over the next 5-10 years.

FOR ELECTRIC UTILITIES, inverter technology promises reliability and efficiency benefits needed to manage growing grid penetrations of PV. But while the technical capabilities of smart inverters are reasonably well understood, practical methods for configuring and deploying the devices are not.

Today, a handful of electric utilities are introducing smart inverters with PV applications. This white paper, a collaboration between the Solar Electric Power Association (SEPA) and the Electric Power Research Institute (EPRI), explores these leading-edge utility smart inverter adoption strategies. It also examines the underlying rationales and value propositions to identify new concepts and business approaches that industry peers may consider when developing their own smart inverter deployment plans.1

Inverters with grid support functionality offer utilities new options to operate existing distribution grids through the direct use of distributed PV and, where applicable, energy storage. Because inverters are a core component of every interconnected PV system, these additional capabilities enhance existing assets and enable an improved grid “handshake.”

Enhanced capabilities, which include reactive power compensation, voltage/frequency ride-through, and

real-time data connectivity, could potentially offer utilities a least cost tool for mitigating many grid management challenges. In some cases, advanced inverters could help defer or avoid certain distribution, transmission, and electric supply upgrades.

Despite these opportunities, unresolved issues related to the devices’ implementation and use have limited deployment. Ongoing revision of voluntary standards (e.g., IEEE 1547), grid codes (e.g., California’s Rule 21), interconnection procedures, and communications protocols are affecting utility rollout approaches. Furthermore, customer privacy concerns and regulatory approval of utility inverter ownership are also influencing rollout tactics.

In the pursuit of effective and equitable smart inverter deployment strategies, utilities in California, Hawaii, and Arizona are tackling these complex issues. These unique approaches—undertaken by Salt River Project (SRP), Arizona Public Service (APS), The Hawaiian Electric Companies, and Pacific Gas & Electric (PG&E)—reflect the various contexts within which smart inverter activity is occurring and highlight key lessons learned that may inform future rollout strategies.

LOOKING TO GERMANY FOR PERSPECTIVEGermany, the worldwide leader in PV deployment with approximately 39 gigawatts (GW) of installed capacity as of mid-2015, has encountered grid management challenges within areas of high PV penetrations that are instructive to grid operators around the world. Among the issues was the “50.2 Hertz (Hz) problem,” which

resulted from rapid deployment of PV systems and deficient requirements for inverter grid support.

Due to a number of factors, including a lucrative feed-in tariff, PV capacity in Germany quickly expanded from negligible levels in 2000, to nearly 18 GW at the end of 2010. Many of the installations were connected to the

low-voltage (LV) distribution network. Not anticipating the large-scale deployment, regulators and utilities failed to implement interconnection rules and behaviors suitable for such PV growth and by 2011, experts began to voice grid reliability concerns.2,3

PV inverters connected to the LV distribution network had been programmed to immediately disconnect when the system frequency exceeded 50.2 Hz (0.2 Hz above nominal). This contingency appeared innocuous with limited PV interconnections, but with growing deployment, the risk of a single contingency cascading into a larger contingency—or frequency oscillation (as shown in Figure 1)—at the bulk system level substantially increased.4

In response, German authorities instituted two reforms for systems connected at the low-voltage distribution network:

1. EXISTING PV SYSTEMS (larger than 10 kW) were required to be retrofitted with a function known as watt-frequency curtailment that gradually inhibits PV output as the system frequency exceeds 50.2Hz (see Figure 2).

WHAT IS A SMART INVERTER?Broadly, “smart” inverters provide some additional benefit to the grid beyond simply converting direct-current (DC) electricity to alternating current (AC) from PV systems. They typically support overall grid reliability by offering one or more of the following features:

u RIDE-THROUGH OF GRID DISTURBANCES—During periods of (sometimes extreme) deviations in grid voltage and/or frequency, smart inverters are designed to remain connected to the grid and adjust their output to act as a counterbalance to frequency or voltage changes.

u VOLTAGE SUPPORT—To help maintain voltage quality—for example in end-of-feeder grid locations where additional generation could result in voltage violations—smart inverters can modulate real (Watts) and reactive (vars) power output.

u OPERATOR INTERACTIVITY— Smart inverters have the capability to interface with the grid operator, and thereby enable dynamic adjustment to settings, behaviors, and in some cases, real-time output. This advanced functionality is intended to address today’s increasingly dynamic grid and its ever-changing composition of generation and load.

These advanced functions are inherently available in most inverters today, but current grid codes, safety standards, and interconnection specifications largely restrict their usage in the U.S.

INVE

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INVERTER OUTPUT CURTAILED ASA FUNCTION OF FREQUENCY

100%SYSTEM

FREQUENCY (HZ)

50.2 Hz

INVERTER FREE TO INJECTMAXIMUM AVAILABLEPOWER INTO THE GRID

FIGURE 2. THE WATT-FREQUENCY CURTAILMENT FUNCTION SMOOTHLY REDUCES PV POWER WHEN GRID FREQUENCY IS INCREASED.

Source: EPRI

0 10 20 30 40 50 60

50.8

50.6

50.4

50.2

50.0

49.8

49.6

49.4

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TIME IN SECONDS

GRI

D F

REQ

UEN

CY IN

HZ

PREVIOUS INTERCONNECTION RULESUPDATED INTERCONNECTION RULESGERMAN OPERATING FREQUENCY LIMIT

FIGURE 1. GERMANY’S PREVIOUS INTERCONNECTION RULES COULD HAVE RESULTED IN REDUCED GRID RELIABILITY.

Source: G. Kaestle and T. K. Vrana

ROLLING OUT SMART INVERTERS 5 SEPA AND EPRI

2. NEW PV SYSTEMS of all sizes became subject to an enhanced grid code (VDE-AR-N-4105) that requires not only watt-frequency curtailment, but also under-frequency ride-through and reactive power support.

To improve the ratio of grid benefits to costs, only PV systems larger than 10 kW—which comprised 86% of Germany’s total solar capacity at the time—were targeted for the retrofit. Adding the watt-frequency curtailment function proved to be a simple software change, but required that a technician install and verify the firmware update on-site. Although the retrofit was limited to larger systems (roughly 440,000 systems totaling 12.3 GW), the costs have been significant. Estimates range from 100 million to 300 million euros, with the retrofit just over half-completed as of August 2014.5 The high cost and long project duration have been attributed to the large number of installed systems requiring retrofit, as well as the logistics of coordinating numerous parties (e.g., installers, network operators, hardware vendors) in the process.

For systems installed after 2012, an updated grid code has been instituted that defines the interaction of the PV inverter with the distribution network.6 Under this new arrangement, inverters larger than 3.68 kW are required to provide reactive power, while inverters of all sizes must remain grid connected with a grid frequency

above 47.5 Hz. Additionally, systems larger than 100 kW must be capable of reducing their active power output at the request of the grid operator. Ride-through of high and low voltage events, as well as more complex (i.e., voltage-dependent) methods of reactive power control, will not be addressed until further study can confirm the associated benefits and/or risks.

Despite advanced inverter functionality requirements, it remains unclear how reactive power support can be used in practice. Due to existing feeder concentrations, distribution operators in Germany continue to upgrade feeders—often by reconductoring or by increasing transformer capacity—to accommodate additional PV systems. As shown in Figure 3, the number of feeders requiring increased cable or transformer capacity continues to increase.

Germany’s experience with smart inverters may help inform strategies governing the technology’s diffusion in other countries. However, it is difficult to directly relate the costs and benefits of the country’s smart inverter rollout to the U.S. For example, Germany’s distribution system is more densely constructed than most systems in the U.S. (e.g., circuits tend to be shorter) and thus the concentration of PV per feeder tends to be much greater (6-7x peak load on some networks). As a result, the potential benefits gained from smart inverters in

Germany, particularly from reactive power support, has not been fully realized. In some cases, feeders were already near their thermal capacity limits, and therefore required upgrade regardless. Still, the country’s experiences have raised general awareness in the U.S. about grid reliability issues posed by rising penetrations of PV, the effect of grid codes, and the challenges of retrofitting inverters with advanced functionality. Documented results have helped inform policy discussions as well as technology enhancements.

0 300 600 900 1200 1500

CONDUCTING SAG REGULATION

CABLE MONITORING

HIGH TEMPERATURE LINES

INSTALLATION OF VOLTAGE REGULATOR

INCREASE IN OVERHEAD CONDUCTOR

CONSTRUCTION OF PARALLEL SYSTEMS

INSTALLATION OF METERING TECHNOLOGY

CHANGES IN NETWORK TOPOLOGY

ISOLATION POINT OPTIMIZATION

UNDERGROUNDING OF OVERHEAD LINES

INCREASE OF CABLE CROSS-SECTIONS

INCREASE IN TRANSFORMER CAPACITY

2011201220132014

FIGURE 3. GERMAN DISTRIBUTION OPERATORS ARE UPGRADING AN INCREASING NUMBER OF FEEDERS TO ACCOMMODATE INSTALLED PV.

Source: Bundesnetzagentur (BNetzA)

ROLLING OUT SMART INVERTERS 6 SEPA AND EPRI

TABLE 1. KEY ELEMENTS OF UTILITY SMART INVERTER ROLLOUT STRATEGIES

UTILITY CONTEXT KEY ROLLOUT HIGHLIGHTS

THE HAWAIIAN ELECTRIC COMPANIES

§ Existing high PV penetrations, mostly distributed rooftop

§ (Since revised) interconnection rules that disallow inverter grid support

§ Islanded grid infrastructure

§ Inverter under-frequency trip limits widened from 59.7 Hz to 57 Hz

§ Ride-through requirements established for PV systems installed after Feb. 2015

§ Existing PV systems retrofitted with ride-through settings, largely through remote software update

ARIZONA PUBLIC SERVICE

§ Substantial utility- and customer-owned PV

§ Considerable growth expectations, given favorable climate, sunshine

§ Utility-owned residential PV pilot aimed at field study

§ Communications platform under development to connect distributed pilot systems with the utility’s control center

PACIFIC GAS & ELECTRIC

§ Existing installs equal to 28% of cumulative U.S. solar capacity

§ Service area has among the highest solar penetration rates in U.S.

§ Compliance with latest revisions to Rule 21

§ Retrofit deemed unnecessary

SALT RIVER PROJECT

§ Considerable PV deployment and annual growth

§ Highly reliable network architecture (e.g., short distribution feeders with high capacity, fully looped)

§ Residential PV inverter pilot to assess a range of operational modes, autonomous functions

§ Dynamic communications to interface with a pilot distribution management system

PROFILING SELECTED U.S. UTILITY ROLLOUT APPROACHESWITHIN THE U.S., a handful of utilities are beginning to pursue smart inverter deployments as shown in Table 1. These utilities are employing a range of rollout approaches governed by differing circumstances and objectives. In one instance, as was the case in Germany, the deployment strategy is a reaction to existing grid operational issues driven by high PV penetration. In

others, plans appear to be more proactively rooted in pilot-based learning and incremental rollout. Furthermore, some strategies are largely based upon their adherence to grid codes, while others have a greater degree of flexibility. What follows are four short profiles of the deployment strategies instituted by U.S. utilities.

ROLLING OUT SMART INVERTERS 7 SEPA AND EPRI

THE HAWAIIAN ELECTRIC COMPANIES

The Hawaiian Electric Companies currently lead the nation in per capita PV

installations.7 Ninety-seven percent of the systems in Hawaii are residential

and roughly 13% of the residential rooftops located on the island of Oahu host a PV array.8 Today,

solar PV (including residential-, commercial-, and utility-scale) accounts for roughly 500 MW of capacity, and equates to approximately 15% of the total installed generating capacity on Oahu.9,10

Like Germany, the majority of the PV systems in Hawaii were installed according to (since revised) interconnection rules that restricted inverter grid support technologies. What makes Hawaii unique, however, is the small, isolated nature of the islands’ grids. Within this context, inverter response to voltage and frequency events is significantly more important, because each grid network must be self-sufficient; it cannot rely on neighboring electricity systems for support. Consequently, both centralized and distributed PV have become essential to the infrastructure of each of the Hawaiian Islands.

To improve inverter response to transient events, Hawaiian Electric initially worked with equipment vendors and installers in 2011 to widen the under-frequency trip limits of connected inverters from the standard 59.7 Hz to a more generous 57 Hz. Another significant step would, however, prove necessary to transform a “must trip by” requirement into a “must ride-through unless” requirement that prevents inverter-based generation from tripping during a transient event, and potentially leaving the grid vulnerable to cascading events.

In early 2014, initial definitions for ride-through for distributed PV inverters were under development in California (Rule 21), and compliant equipment

was still at least a year away. Around this time, Hawaiian Electric, working alongside industry and

the Hawaii Public Utilities Commission, developed additional requirements for both voltage and frequency ride-through suitable for their island systems.11 The result was a requirement that new PV systems installed after February 2015 have embedded ride-through functionality in order to better support bulk system reliability.12 As of this writing, the utility and other stakeholders are still exploring the merits of adding voltage support and remote configurability requirements to PV inverters. Because Hawaii’s distribution feeders are fairly compact, making PV concentrations reasonably dense (similar to Germany), voltage management issues have been determined to be less pressing than overall system reliability needs. Going forward, inverter ride-through requirements will be stipulated as part of the interconnection agreement for new systems.

Beyond the development of requirements for new systems, Hawaiian Electric has also recommended retrofitting existing PV systems with ride-through settings. Given the quantity of small, residential PV systems, especially on the island of Oahu, retrofits requiring a site visit from a technician could have been both cumbersome and costly. But the inverter manufacturer Enphase was able to conduct an over-the-air software update that added the necessary functionality to the majority of its installed inverter base. In a single day, 800,000 individual micro-inverter units on the island that controlled 140 MW (roughly half of Oahu’s PV capacity) were reprogrammed with the new features.13

WHAT MAKES HAWAII UNIQUE...IS THE SMALL, ISOLATED NATURE OF THE ISLANDS’ GRIDS...INVERTER RESPONSE TO VOLTAGE AND FREQUENCY EVENTS IS SIGNIFICANTLY MORE IMPORTANT, BECAUSE EACH GRID NETWORK MUST BE SELF-SUFFICIENT; IT CANNOT RELY ON NEIGHBORING ELECTRICITY SYSTEMS FOR SUPPORT

THE HAWAIIAN ELECTRIC COMPANIES CURRENTLY LEAD THE NATION IN PER CAPITA PV INSTALLATIONS.

ROLLING OUT SMART INVERTERS 8 SEPA AND EPRI

ARIZONA PUBLIC SERVICE

APS, an investor-owned utility (IOU) headquartered in Phoenix, Arizona, is also adapting to surging growth in solar electricity. The utility’s generation portfolio includes significant amounts of

large-scale utility-owned and third-party owned solar (approximately 480 MW as

of the end of 2014). In addition to larger systems, APS estimates that another 396 MW of distributed solar is active behind the meter, with continued growth

expected into the future.14 APS is studying the possible impact of increased PV penetration, while exploring new technologies to mitigate associated challenges.

In its newly launched Solar Partner Program (SPP), APS is rolling out smart inverters as part of a utility-owned residential solar pilot in the Phoenix metro area. The program charter calls

for the implementation of 1,500 rooftop systems—totaling up to 10 MW. The rollout is based on customer participation, and is focused on select areas of the service territory that provide the greatest research benefit. To better align solar output with peak system demand, APS is targeting participants with west- or southwest-facing rooftops. Additionally, grid-tied battery storage will be installed on two feeders to enable APS to study the benefits and preferred methods for coordinating storage with PV output.

SPP systems will interconnect on the utility’s side of the meter. In exchange for rooftop space, participating customers will receive a $30 per month bill credit. These systems will comprise entirely new construction and be deployed by Arizona-based installers.

APS will leverage the SPP systems to field test a variety of research questions germane to high penetration solar deployment that, up to this point, have only been considered in computer-based simulations. A number

of “use cases” will guide the research effort and the SPP, including:

1. Distributed PV equipment deferment options

2. Smart inverter voltage management use

3. Smart inverter effectiveness during “stress” conditions

a. Distribution feeders with high solar deployment

b. Circuits with a large number of regulating devices (e.g., capacitor banks, line regulators)

4. Functionality and coordination of smart inverters with a central controller

5. Best practices for utility control center communication with smart inverters

6. Energy storage system coordination

7. Real-world PV behavior reconciliation with established electrical models

8. Accuracy and usefulness of existing solar forecasting method assessment

APS is developing a communications and control platform to connect the 1,500 distributed systems with the utility’s control center to allow for real-time data transfer between the utility and the smart inverters. The control system will be able to update settings, command inverter responses during contingencies, and leverage the inverters’ sensor data for feedback on operations and overall power quality.

APS believes the knowledge gained from this program has long-term benefits and can assist the broader utility and solar industries. It has augmented its research capability by partnering directly with EPRI and has created an Advisory Council composed of thought leaders and technical experts from various universities, EPRI, SEPA, the national labs, the Arizona consumer advocate (Residential Utility Consumer Office), the Arizona Corporation Commission, and several other utilities.

APS IS DEVELOPING A COMMUNICATIONS AND CONTROL PLATFORM TO CONNECT THE 1,500 DISTRIBUTED SYSTEMS WITH THE UTILITY’S CONTROL CENTER TO ALLOW FOR REAL-TIME DATA TRANSFER BETWEEN THE UTILITY AND THE SMART INVERTERS.

ROLLING OUT SMART INVERTERS 9 SEPA AND EPRI

PACIFIC GAS & ELECTRIC

San Francisco-based PG&E is a leading “solar utility” in the U.S. with more than 4.6 GW online in its service territory as of the end of

2014—equal to 28% of the total installed capacity in the U.S. at that time.15 Serving 5.3 million customer accounts in central and northern California, the utility has among the highest solar penetration rates in the nation,

averaging 869 Watts of solar per customer.16

Unlike the other inverter implementations featured in this paper, PG&E’s strategy is essentially rooted in compliance with new state-level requirements stipulated in recent revisions to California Public Utilities Commission’s (CPUC) Rule 21, the tariff that ascribes the technical interconnection, operation, and metering requirements for connecting distributed generators to

California’s electric system. As such, PG&E along with the state’s other IOUs, are following the administrative rules to rollout smart inverters in their respective service areas.

Rule 21 has recently been amended to support advanced

inverter functionality as a means to expanding solar interconnections. The revisions are the product of a multi-year effort undertaken by the Smart Inverter Working Group (SIWG), formed by the CPUC and the California Energy Commission, to identify and overcome the technical challenges of incorporating advanced inverters into grid operations. Comprised of more than 50 organizations including PG&E, other utilities, manufacturers, and solar developers, the SIWG collaboration has provided an open forum for revising Rule 21.

The Rule 21 amendments will be implemented in three phases (as depicted in Figure 4). Phase 1, scheduled to commence in early 2016, will enable autonomous inverter operations only.17 Phase 2 will incorporate IEC 6185018 and IEEE 2030.5 (SEP 2.0)19 communications capabilities and cybersecurity measures, the technical requirements and associated schedule of which are still under development as of this writing.20 Finally, Phase 3, still in early development stages, will implement advanced functionality through more robust integration with dynamic controls and inverter dispatchability.

As written in the revision language, new inverter functionality must be implemented for all new solar interconnections within one year of the finalized update to the UL 1741 SA testing procedures, expected to occur in late 2015. UL 1741 is an equipment safety

FIGURE 4. OVERVIEW OF REVISED RULE 21 IMPLEMENTATION PHASES

PHASE 1 PHASE 2 PHASE 3

§ Anti-Islanding

§ Voltage Ride-through

§ Frequency Ride-through

§ Volt-Var Control

§ Ramp Rate Control

§ Fixed Power Factor

§ Modular Capability for Communications

§ TCP/IP Addressability

§ IEC 61850 Compliant

§ Cybersecurity

§ Emergency Alarms

§ Status of Energy Ancillary Services

§ Limit PCC Export on Utility Command

§ Disconnect + Reconnect on Command

Source: “Recommendations for Updating the Technical Requirements for Inverters in Distributed Energy Resources.” SIWG. January 2014

RULE 21 HAS RECENTLY BEEN AMENDED TO SUPPORT ADVANCED INVERTER FUNCTIONALITY AS A MEANS TO EXPANDING SOLAR INTERCONNECTIONS.

ROLLING OUT SMART INVERTERS 10 SEPA AND EPRI

standard that certifies a specific piece of equipment as safe for a given use, and it applies to inverters, converters, controllers and interconnection equipment for use with distributed energy resources (DER). Each enhanced inverter function affected by Rule 21 requires a new equipment safety test to be administered by UL. When these revisions are completed and issued, the associated testing procedures will be used for inverter equipment certification.

Phase 1 will primarily implement autonomous functionality including expanded ride-through parameters and power quality support among other functions.21 These functions do not require robust communication schemes to facilitate complex interaction with other utility systems, including substations, distribution management systems, and advanced metering infrastructure. Current standards require inverters to trip off if grid frequency or voltage deviates from a narrowly defined operating window. The expanded ride-though settings in Rule 21 are

intended to keep inverters connected to the grid longer during system disturbances.

PG&E actively monitors the penetration of distributed generation on its feeders. Currently, the total distributed generation penetration on the distribution system is

about 10% of peak load, 80% of that is PV, but individual feeders range from 0% to beyond 200% of the feeder’s peak load. At the rate solar has grown on its system, many circuits are expected to reach 100% of peak

load by around 2020. Because each project is reviewed/mitigated prior to interconnection, PG&E does not expect any significant distribution system issues to result from high penetration levels.

In addition to ride-through, Rule 21 Phase 1 calls for an adjustable volt/var setting. By default, this function will not be enabled in order to avoid potentially unstable inverter interactions that could cause local voltage to exceed CPUC limits. The utility will have the discretion to activate it after a study of the circuit to ensure that the inverters can be coordinated and used as resources for reactive power. The use of inverters for var support in this way must not come at the expense of real power output.

Utilities in California have the flexibility to implement Rule 21 before the effective deadline, and PG&E may do so on a case-by-case basis as feeder conditions warrant. The utility has not yet implemented any inverters in compliance with Phase 1. Despite the vast deployment of PV in PG&E’s service territory to date, the utility has no plans to retrofit inverters on previously installed systems. Revised Rule 21 requirements will be mandated for new interconnections, but existing installations will be grandfathered.

CURRENTLY, THE TOTAL DISTRIBUTED GENERATION PENETRATION ON THE DISTRIBUTION SYSTEM IS ABOUT 10% OF PEAK LOAD. 80% OF THAT IS PV, BUT INDIVIDUAL FEEDERS RANGE FROM 0% TO BEYOND 200% OF THE FEEDER’S PEAK LOAD.

DESPITE THE VAST DEPLOYMENT OF PV IN PG&E’S SERVICE TERRITORY TO DATE, THE UTILITY HAS NO PLANS TO RETROFIT INVERTERS ON PREVIOUSLY INSTALLED SYSTEMS.

ROLLING OUT SMART INVERTERS 11 SEPA AND EPRI

SALT RIVER PROJECT

SRP is a public power utility that provides electricity services to more than 1 million customers in central Arizona. At the end of 2014, the utility had integrated 138 MW of solar power in its territory placing it in

the top 20 utilities nationally, according to SEPA’s annual survey of utilities. Solar

growth in SRP’s territory has averaged 50 percent annually since 2011, which is twice the national average.

SRP has a highly reliable network with 80% of the distribution system underground. Outages on average are restored within two hours, due in part, to the characteristics of the utility’s distribution system. Each of the utility’s distribution feeders runs relatively short

distances, has high capacity, and is fully looped, meaning it can be backed up by adjacent feeders.

SRP is in the process of initiating an Advanced Inverter Project as a multi-year collaborative research initiative

with EPRI. For the study, SRP’s objective is to deploy approximately 1,000 advanced inverters behind the customer meter in residential applications to evaluate advanced functions and settings. The utility is exploring the potential for licensing agreements or hardware ownership as a means to enable advanced functionality for inverters installed behind the customer meter. Results of this study are intended to inform future interconnection requirements.

SRP plans to deploy three categories of advanced inverters:

u CATEGORY 1: inverters set to function autonomously

u CATEGORY 2: inverters with limited communications capabilities, with settings modified seasonally

u CATEGORY 3: inverters with dynamic communication capabilities that interface with a pilot distribution management system (DMS) on a single circuit

Operationally, Category 1 will closely resemble California’s Rule 21 Phase 1 implementation (see PG&E case study on page 9). In both cases the inverters will use wider ride-through settings for frequency and voltage, and have the option to provide dynamic volt/var operations and to set a non-unity power factor. Inverter behaviors will be responsive to detected grid conditions only, without an option for grid operators to dispatch additional functionality through communications systems.

Category 2 inverters will differ from those in Category 1 by being enabled with operating profiles that change seasonally with settings optimized for weather and load conditions at different times of the year. For example during summer months, air conditioning increases feeder load, while the longer days with greater solar irradiance increase distributed solar PV output. By more closely matching inverter performance with grid conditions via seasonal profiles, this set of advanced inverters is intended to have a more targeted impact on grid integration of solar resources and distribution system operations.

Category 3 inverters will be equipped with high speed communication capabilities and will be connected to the utility’s pilot DMS to enable interactivity between SRP and the distributed solar assets. In this way, inverter functions will be able to be actively modified in response to grid conditions. Inverters in this category will be endowed with the same functionality as prior categories, but will be able to respond more dynamically to grid conditions.

In addition to testing the operational benefits of advanced inverters, SRP will also evaluate the effectiveness of its communications network to manage inverters, and adequacy of cybersecurity measures. Communications capabilities are not required for Category 1 inverters, but they will be deployed for Categories 2 and 3.

SRP plans to use wireless communications to enable changes to both Category 2 and 3 inverters. Enabling and updating the seasonal profiles for the Category 2 inverters will not require high bandwidth connectivity. Category 3 communications, on

SRP HAS A HIGHLY RELIABLE NETWORK WITH 80% OF THE DISTRIBUTION SYSTEM UNDERGROUND. OUTAGES ON AVERAGE ARE RESTORED WITHIN TWO HOURS.

SOLAR GROWTH IN SRP’S TERRITORY HAS AVERAGED 50 PERCENT ANNUALLY SINCE 2011, WHICH IS TWICE THE NATIONAL AVERAGE.

ROLLING OUT SMART INVERTERS 12 SEPA AND EPRI

the other hand, will require high-speed communications to transmit telemetry and actively control the inverter

functionality in real time. One of the goals of the project is to determine whether the planned communications infrastructure is sufficient to effectively control the advanced inverters in real time.

UL 1741, the industry certification ensuring inverters operate safely, must be updated

to test and certify that devices can provide advanced functionality in a safe manner. According to SRP, this

safety certification is essential for inverters that will be used in its retrofit study. Once UL listed inverters are available, SRP can move forward with deploying the advanced inverters.

Without national standards for interconnection or interoperability of advanced inverters with utility infrastructure, SRP has found it necessary to collaborate directly with manufacturers to appropriate hardware that meets its residential inverter specifications. This is an iterative process that has led to some delays during SRP’s preliminary testing while manufacturers adapt their inverters to Advanced Inverter Project specifications. This is an important consideration for other utilities as they research advanced functionality from residential inverters (large-scale inverters commonly provide grid supporting functions).

KEY FINDINGSWith significant growth in PV deployment over the last few years, utilities are paying more attention to the grid support potential of smart inverters. Interconnection standards are being revised to allow active voltage support and more robust response to grid disturbances. Now the industry is grappling with the details of when and how to require smart inverters and what settings and functions to demand. This white paper reviewed several utilities strategies for unlocking advanced inverter functionality. Given the momentum of solar and the magnitude of the potential grid integration challenge, other utilities may soon be considering rollout strategies of their own.

Germany’s experience with smart inverters captured the attention of many in the U.S., and has proven somewhat instructive. However, differences in power system operation and design have limited the degree to which strategic insights can be applied to U.S. efforts. At a minimum, Germany’s experience did clearly demonstrate the technical and financial pitfalls of using interconnection protocols now considered outmoded. But, except for the frequency ride-through requirement, German utilities have rarely accessed the advanced functions now embedded in a majority of the country’s installed inverters. German distribution circuits are still being reinforced through reconductoring and by increasing transformer capacity. Consequently, U.S.

rollouts are not uniformly following Germany’s lead; they are instead charting a diversity of courses motivated by situational specifics and general learning.

Hawaii’s smart inverter adoption tactics are perhaps most similar to Germany’s, but with important distinctions. Like their German counterparts, much of the Hawaiian Electric Companies’ actions have been borne of necessity. The growing grid penetration of distributed solar on Hawaii’s islanded grids has forced attention to bulk system reliability issues, updating interconnection rules, and retrofitting installed inverters with advanced functions. In particular, the isolated nature of Hawaii’s grids has placed greater importance on the inverter’s response to grid voltage and frequency variations. Moreover, Hawaii’s inverter rollout has, like Germany, benefited from a robust solar market, which has prompted significant customer and solar industry participation, regulator attention, as well as stakeholder collaboration and planning.

On the mainland, a transition to smart inverters seems to lack the same urgency as Hawaii. Stakeholders are more methodically determining if and when the technology will be required. California’s approach is statewide. Meanwhile, Arizona utilities, SRP and APS, have proactively initiated multi-year research pilots to evaluate a limited deployment of smart inverters. In New

IN ADDITION TO TESTING THE OPERATIONAL BENEFITS OF ADVANCED INVERTERS, SRP WILL ALSO EVALUATE THE EFFECTIVENESS OF ITS COMMUNICATIONS NETWORK TO MANAGE INVERTERS, AND ADEQUACY OF CYBERSECURITY MEASURES.

ROLLING OUT SMART INVERTERS 13 SEPA AND EPRI

York, individual feeder studies have been performed with smart inverters, but it remains to be seen whether statewide requirements through regulatory activities, such as NY REV, will impact deployment requirements.

That said, four common themes emerged among the case studies illustrated in this white paper that also apply to the industry at-large. These include:.

1. EQUIPMENT STANDARDS ARE NOT KEEPING PACE WITH TECHNOLOGY ADVANCEMENT.Two important standards governing the safety, reliability, and electrical performance of DER—UL 1741 and IEEE 1547—are being revised to facilitate the expanded functionality of advanced inverters. Until these updates are finalized, advanced inverter functionality cannot be certified for many use cases, delaying field deployment. Although utilities are not prevented from rolling out advanced inverters before the standards are finalized, they are unlikely to do so due to the potential for legal liability resulting from an equipment malfunction on a customer’s premises.

These updated standards will not dictate the implementation of advanced inverter functionality, so studies and pilots will be necessary to evaluate how to best leverage this new technology effectively.

2. AUTONOMOUS GRID SUPPORT FUNCTIONALITY CAN BE READILY DEPLOYED AT LOW COST. All of the utility implementation strategies include autonomous behavior of advanced inverters for frequency and voltage ride-through, ramp rate control, and fixed power factor functions. These low cost functions hold significant operational benefits for utilities, and UL 1741 and IEEE 1547 updates are expected to facilitate their deployment.

Though smart inverters can provide some grid support functionality at a minimal incremental cost, expensive communications infrastructure is necessary to maximize the grid benefits of many advanced inverter functions. This connectivity adds

more deployment cost than the incremental cost for the advanced inverter hardware alone. As a result, autonomous functionality has been a common theme among pilot projects to deliver grid benefits, while avoiding costly communication investments.

3. COMMUNICATIONS-BASED FUNCTIONALITY REMAINS A TRADEOFF BETWEEN INVERTER CAPABILITIES AND IMPLEMENTATION COST.Distribution optimization is being considered through the integration of inverter hardware with utility SCADA and other control software such as DMS or distributed energy resource management systems (DERMS).22 Major challenges include utility access to needed data and the analytical capability to process the data and update communication settings to alter distributed generation assets. Communications bandwidth will be required to interconnect and manage DER. In recognition of this, PG&E and Rule 21 have delayed the implementation of communications-enabled functionality until Phase 2. Similarly, SRP plans to target its highest capacity communications to a single high DER penetration circuit. The limited implementation is intended to keep communications costs manageable, while testing and quantifying the incremental benefits to the grid.

4. INVERTER RETROFITS CAN BE EFFECTIVELY MANAGED.Thus far, utilities in the U.S. have avoided costly inverter retrofit efforts. Sufficient time remains, even in areas with the greatest grid penetration, to implement a deployment strategy. Even in Hawaii, where feeder penetrations are highest, Hawaiian Electric has worked with stakeholders to ensure that inverters deployed on its system can support the grid during modeled disturbances. It has, furthermore, successfully overseen a relatively inexpensive remote software update to more than 800,000 microinverters. Other U.S. utilities have reported that similar retrofits will not be necessary.

ROLLING OUT SMART INVERTERS 14 SEPA AND EPRI

CONCLUSION AND FUTURE CONSIDERATIONS Rising grid penetration of variable solar generation—driven by technology advancements, supportive policies, and improving project economics—are expected to introduce greater variability to the grid, thereby increasing the importance of ancillary services. For utilities, the advanced functions embedded in smart inverters offer a means for supporting the distribution system and accommodating the further adoption of grid edge assets. The challenge facing the industry over the next several years and beyond will be to determine how to practically deploy and operate them.

Greater utility familiarity with smart inverters as well as the further evolution of guiding standards and grid codes are likely to enable the gradual emergence of optimal electric utility rollout strategies. Absent a national grid code in the U.S., however, no single approach is likely to take root. Instead, divergent deployment strategies will incorporate core elements—universal vs. selective adoption, full advanced inverter functionality vs. more basic power factor capability, adherence to state-wide smart inverter policy vs. market-based doctrines—that will be based upon

context-specific distribution system attributes, load growth forecasts, and cost-benefit calculations.

Research from EPRI, SEPA, and others will continue to evaluate the efficacy of smart inverter technologies as it relates to individual markets and utility business models. For example, SEPA, in collaboration with NREL, will release a market report for advanced inverters in Q4 2015 that will delve into the current state of utility activity around this technology as well as the barriers to its adoption. Meanwhile, as part of its Integrated Grid research initiative23, EPRI will evaluate autonomous inverter functions in lab and field settings, assess inverter communications connectivity with utility DERMS and SCADA systems, and model the technical and economic impacts of inverter’s grid-supportive functions at both the feeder and system levels.

The promise of smart inverter technology is likely to spur further pilot and full-scale rollout of the technology by electric utilities in the near future. With experimentation and “learning by doing” we expect viable pathways forward to be clarified.

ACKNOWLEDGEMENTSChase Sun, Darren Deffner (PG&E); Scott Scharli, Lori Singleton, Grant Smedley, Catherine O’Brien (SRP); Erika Myers, Ken Kassakhian (SEPA); Arndt Börkey (Bundesverband Neue Energiewirtschaft e.V.), Scott Bordenkircher (APS), Tom Key, Lindsey Rogers (EPRI).

ENDNOTES1 This white paper builds on the 2014 SEPA report, Unlocking

Advanced Inverter Functionality: Roadmap to a Future of Utility Engagement and Ownership, and the 2013 EPRI report, Utility Ownership of Distributed Inverters.

2 Jens. C. Boemer, Karsten Burges, et al, “Overview of German Grid Issues and Retrofit of Photovoltaic Power Plants in Germany for the Prevention of Frequency Stability Problems in Abnormal System Conditions of the ENTSO-E Region Continental Europe,” in 1st International Workshop on Integration of Solar Power into Power Systems, 2011.

3 G. Kaestle and T. K. Vrana, “Improved Requirements for the Connection to the Low Voltage Grid,” in 21st International Conference on Electricity Distribution (CIRED), 2011.

4 To put this situation in context, researchers have estimated that automatic disconnect of all of Germany’s PV connected at LV could have conceivably removed 9 GW of nominal power instantaneously from the grid.

5 Mirco Sieg, Germany retrofits 200,000 PV installations to meet 50 Hz requirement, PV Magazine. 2014. Available: http://www.pv-magazine.com/news/details/beitrag/germany-retrofits-200-000-pv-installations-to-meet-50-hz-requirement_100016243/#axzz3fsMEeZGx

6 A grid code differs from a standard in that once it is ratified, it is a requirement for all generators. U.S. interconnection agreements typically reference a voluntary standard (such as IEEE 1547) that is not a requirement in and of itself.

7 The Hawaiian Electric Companies serve the islands of Oahu (Hawaiian Electric); Maui, Molokai, and Lanai (Maui Electric); and Hawaii Island (Hawaii Electric Light). Each island is operated as an isolated system.

8 “Hawaiian Electric Industries Reports 2014 Year-End & Fourth Quarter Earnings.” Hawaiian Electric Industries (HEI). Available: http://www.hei.com/phoenix.zhtml?c=101675&p=irol-newsArticle&ID=2016459

9 “Cumulative Installed PV Capacity – June 30th 2015” Hawaiian Electric. Available: http://www.hawaiianelectric.com/vcmcontent/StaticFiles/pdf/PVSummary_2ndQtr2015.pdf

10 “Company Facts” Hawaiian Electric. Available: http://www.hawaiianelectric.com/heco/About-Us/Company-Facts. Last Accessed: 7/22/2015

11 Transient Over-Voltage and Frequency & Voltage Ride-Through Requirements for Inverter-Based Distributed Generation Projects, Hawaiian Electric. February 2015. Available: http://www.hawaiianelectric.com/vcmcontent/StaticFiles/pdf/TrOVandFVRT_Public_Feb2015.pdf

12 According to Hawaiian Electric, new systems as of February 2015 were to be ride-through capable, with those features initiated by September 2015.

13 Peter Fairley, “800,000 Microinverters Remotely Retrofitted on Oahu—in One Day,” IEEE Spectrum, 05 Feb. 2015, http://spectrum.ieee.org/energywise/green-tech/solar/in-one-day-800000-microinverters-remotely-retrofitted-on-oahu.

14 “2014 Annual Report.” Pinnacle West Capital Corporation. Phoenix, AZ. Available: http://www.azenergyfuture.com/getmedia/d2202ba5-41aa-4ef2-b8c1-411d2f074654/PNW_2014_Annual_Report.pdf/?ext=.pdf

15 SEPA 2014 Annual Solar Market Survey. For perspective, the #2 utility, Southern California Edison, has half as much solar in its portfolio as PG&E.

16 SEPA 2014 Annual Solar Market Survey

17 Note that Phase I doesn’t include any functions that modify real power output. Voltage support is provided in a “VAR-preference” mode, meaning that support is only offered when the inverters’ capacity is not being used to generate real power.

18 IEC 61850 is a standard for the design of electrical substation automation.

19 IEEE 2030.5, also known as the Smart Energy Profile 2.0 (SEP 2), is the default protocol which must be supported by individual DER systems in order to communicate with the utility in support of smart inverter-defined functionality.

20 CEC and CPUC Recommendations for Utility Communications with Distributed Energy Resources (DER) Systems with Smart Inverters. Smart Inverter Working Group Phase 2 Recommendations Draft v9. February 28, 2015. http://www.energy.ca.gov/electricity_analysis/rule21/documents/SIWG_Phase_2_Communications_Recommendations_for_CPUC.pdf

21 See Table 2

22 A Distributed Energy Resource Management System (DERMS) is a software-based solution that increases an operator’s real-time visibility into its underlying distributed asset capabilities

23 For further information, see EPRI’s Integrated Grid Online Community: http://integratedgrid.epri.com.

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