Experiences in Integrating PV and Other DG to the Power System

Experiences in Integrating PV and Other DG to the Power System (Radial Distribution Systems) Prepared by: Philip Barker Founder and Principal Engineer Nova Energy Specialists, LLC Schenectady, NY Phone (518) 346-9770 Website: novaenergyspecialists.com E-Mail: pbarker@nycap.rr.com Presented at: Utility Wind Interest Group (UWIG) 6 th Annual Distributed Wind/Solar Interconnection Workshop February 22-24, 2012 Golden, CO Prepared by Nova Energy Specialists, LLC 1

Topics Discussion of Distribution and Subtransmission Factors Considered in Basic DG integration Studies Useful Ratios for Screening Analysis of DG Impacts Review of Some System Impacts: Voltage Issues Fault Current Issues Islanding Issues Ground Fault Overvoltage Issues Summary and Conclusions of PV Experiences Prepared by Nova Energy Specialists, LLC 2

Discussion of Some Factors to Consider in DG Integration Alt. Feed Other Substations with Load and DG LTC 12.47 kv Subtransmission Line Substation Transformer Reclosing and Relay Settings Subtransmission Source Bulk System Regulator and LTC Settings Adjacent Feeders Other load and DG scattered on feeder Distribution Feeder Voltage Regulator Step Up Transformer DG Type of Grounding Rotating Machine or Inverter based DG Primary Feeder Point of Connection (POC) Alt. Feed Capacitor Customer Site Load Prime mover or energy source characteristics Prepared by Nova Energy Specialists, LLC 3

Some Useful Penetration Ratios for Screening Analysis Minimum Load to Generation Ratio (this is the annual minimum load on the relevant power system section divided by the aggregate DG capacity on the power system section) Stiffness Factor (the available utility fault current divided by DG rated output current in the affected area) Fault Ratio Factor (also called SCCR) (available utility fault current divided by DG fault contribution in the affected area) (Note: also called Short Circuit Contribution Ratio: SCCR) Ground Source Impedance Ratio (ratio of zero sequence impedance of DG ground source relative to utility ground source impedance at point of connection) Note: all ratios above are based on the aggregate DG sources on the system area of interest where appropriate Prepared by Nova Energy Specialists, LLC 4 NREL Workshop on High Penetration PV: Defining High Penetration PV Multiple Definitions and Where to Apply Them Phil Barker, Nova Energy Specialists, LLC

Minimum Load to Generation Ratio (MLGR) Peak Load Weekdays Minimum Load Weekend Annual Minimum Load Time (up to 1 year is ideal) False Minimum Try to use the annual minimum load (don t just assume 1 week of measurements gives the minimum) Prepared by Nova Energy Specialists, LLC 5

Some Helpful Screening Thresholds the Author Uses in His Studies Name of Ratio Minimum Load to Generation Ratio [MLGR] (2) What is Ratio useful for? (Note: these ratios are intended for distribution and subtransmission system impacts of DG for the types of impacts described below.) MLGR used for Ground Fault Overvoltage Suppression Analysis (use ratios shown when DG is not effectively grounded) MLGR used for Islanding Analysis (use ratios 50% larger than shown when minimum load characteristics are not well defined or if significant load dropout is a concern during sags.) Suggested Penetration Level Ratios (1) Very Low Penetration (Very low probability of any issues) >10 Synchronous Gen. Moderate Penetration (Low to minor probability of issues) 10 to 5 Synchronous Gen. Higher Penetration (4) (Increased probability of serious issues. Less than 5 Synchronous Gen. >6 6 to 3 Less than 3 Inverters (3) Inverters (3) Inverters (3) >4 4 to 2 Less than 2 Notes: 1. Ratios are meant as guides for radial 4-wire multigrounded neutral distribution system DG applications and are calculated based on aggregate DG on relevant power system sections 2. Minimum load is the lowest annual load on the line section of interest (up to the nearest applicable protective device). Presence of power factor correction banks that result in a surplus of VARs on the islanded line section of interest may require slightly higher ratios than shown to be sure overvoltage is sufficiently suppressed. 3. Inverters are inherently weaker sources than rotating machines therefore this is why a smaller ratio is shown for them than rotating machines 4. If DG application falls in this higher penetration category it means some system upgrades/adjustments are likely needed to avoid power system issues. Prepared by Nova Energy Specialists, LLC 6 NREL Workshop on High Penetration PV: Defining High Penetration PV Multiple Definitions and Where to Apply Them Phil Barker, Nova Energy Specialists, LLC

Screening Ratios (Continued) Type of Ratio Fault Ratio Factor (I SCUtility /I SCDG ) Ground Source Impedance Ratio (2) Stiffness Factor (I SCUtililty /I RatedDG ) What is it useful for? (Note: these ratios are intended for distribution and subtransmission system impacts of DG for the types of impacts described below.) Suggested Penetration Level Ratios (1) Very Low Penetration (Very low probability of any issues) Moderate Penetration (Low to minor probability of issues) Overcurrent device coordination Overcurrent device ratings >100 100 to 20 Ground fault desensitization Overcurrent device coordination and ratings Voltage Regulation (this ratio is a good indicator of voltage influence. Wind/PV have higher ratios due to their fluctuations. Besides this ratio, may need to check for current reversal at upstream regulator devices.) >100 100 to 20 >100 PV/Wind > 50 Steady Source 100 to 50 PV/Wind 50 to 25 Steady Source Higher Penetration (3) (Increased probability of serious issues. Less than 20 Less than 20 Less than 50 PV/Wind Less than 25 Steady Source Notes: 1. Ratios are meant as guides for radial 4-wire multigrounded neutral distribution system DG applications and are calculated based on aggregate DG on relevant power system sections 2. Useful when DG or it s interface transformer provides a ground source contribution. Must include effect of grounding step-up transformer and/or accessory ground banks if present. 3. If DG application falls in this higher penetration category it means some system upgrades/adjustments are likely needed to avoid power system issues. Prepared by Nova Energy Specialists, LLC 7 NREL Workshop on High Penetration PV: Defining High Penetration PV Multiple Definitions and Where to Apply Them Phil Barker, Nova Energy Specialists, LLC

What Does it Mean if it Falls Into the Higher Penetration Category? If the DG application falls into these higher penetration categories, then a detailed study is generally recommended and may lead to the need for mitigation Prepared by Nova Energy Specialists, LLC 8 NREL Workshop on High Penetration PV: Defining High Penetration PV Multiple Definitions and Where to Apply Them Phil Barker, Nova Energy Specialists, LLC

In addition to the ratios discussed in the prior slides, also check for: Reverse power flow at any voltage regulator or transformer LTC bank: if present, check compatibility of the controls and settings of regulator controls. Check line drop compensation interaction: if employed by any upstream regulator, do a screening calculation of the voltage change seen at the regulator with the R and X impedance settings actually employed at the regulator. Generally, if ΔV < 1% seen by the regulator controller calculated for the full rated power change of DG, then line drop compensation effects and LTC cycling is not usually an issue. Capacitor Banks: if significant VAR surplus on a possible islanded area study for potential impact Fast Reclosing Dead Times: if less than 5 seconds (especially those less than 2 seconds) consider the danger of reclosing into live island. Prepared by Nova Energy Specialists, LLC 9

Caveats for Use of the Ratios & Checks Ratios we have discussed on preceding slides are only guides for establishing when distribution and subtransmission system effects of DG become significant to the point of requiring more detailed studies and/or potential mitigation options. They must be applied by knowledgeable engineers that understand the context of the situation and the exceptions where the ratios don t work It requires a lot more than just these slides here to do this topic justice. We have omitted a lot of details due to the short presentation format so this is just meant as a brief illustration of these issues. Prepared NREL by Workshop Nova Energy on High Specialists, Penetration LLC PV: Defining High Penetration PV Multiple Definitions and Where to Apply Them Phil Barker, Nova Energy Specialists, LLC 10

Voltage Regulation & Variation Issues Steady State Voltage (ANSI C84.1 voltage limits) Voltage Excursions and LTC Cycling Voltage Flicker Line Drop Compensator Interactions Reverse Power Interactions Regulation Mode Compatibility Interactions Prepared by Nova Energy Specialists, LLC 11

High Voltage Caused by Too Much DG at End of Regulation Zone LTC V IDG X Sin SUBSTATION Feeder (with R and X) RCos Large DG exports large amounts of power up feeder I DG DG current at angle IEEE 1547 trip Limit (132 Volts) Voltage ANSI C84.1 Upper Limit (126 volts) Light Load (DG at High Output) ANSI C84.1 Lower Limit (114 volts) Heavy Load No DG Heavy Load (DG High Output) Distance Prepared by Nova Energy Specialists, LLC 12 End

Voltage Impact of Distributed Generation on Line Drop Compensation Exporting DG shields the substation LTC controller from seeing the feeder current. The LTC sees less current than there is and does not boost voltage adequately. SUBSTATION LTC Line drop compensator LTC Controller CT Heavy Load No DG DG Supports most of feeder load Large DG (many MW) ANSI C84.1 Upper Limit (114 volts) Heavy Load with DG Light Load No DG ANSI C84.1 Lower Limit (114 volts) Distance End Prepared by Nova Energy Specialists, LLC 13

Voltage Regulator Reverse Mode Confused by DG Reverse Power SUBSTATION LTC Normally Closed Recloser Supplementary Regulator with Bi- Directional controls Normally Open Recloser R R Supplementary regulator senses reverse power and erroneously assumes that auto-loop has operated it attempts to regulate voltage on the substation side of the supplementary regulator Reverse Power Flow Due to DG DG What happens? Since the feeder is still connected to the substation, the line regulator once it is forced into the reverse mode will be attempting to regulate the front section of the feeder. To do this can cause the supplementary regulator to runaway to either its maximum or minimum tap setting to attempt to achieve the desired set voltage. This in turn could cause dangerously high or low voltage on the DG side of the regulator. This occurs because the source on DG side of regulator is voltage following (not aiming to a particular voltage set point) and is weak compared to the substation source. Prepared by Nova Energy Specialists, LLC 14

Fluctuating Output of a Photovoltaic Power Plant 1 2 3 4 5 6 7 8 9 Days Prepared by Nova Energy Specialists, LLC 15

Flicker The GE Flicker Curve (IEEE Standard 141-1993 and 519-1992) Screening: Using the voltage drop screening formula to estimate the ΔV for a given DG current change (ΔI DG ). Then plot ΔV on the flicker curve using expected time period between fluctuations System Impedance ΔI DG Infinite Source R X DG Starting Current and DG Running current fluctuations V I DG X Sin DG RCos V Flicker Voltage Example Realize that this is a basic screening concept. For situations where there might be more significant dynamic interactions with other loads, or utility system equipment, a dynamic simulation with a program such as EMTP or PSS/E may be required to verify if flicker will be visible. Prepared by Nova Energy Specialists, LLC 16

Percent Voltage Change ( V%) A Conservative Quick Screen for PV Flicker (Not as accurate as IEEE 1453 method but easy and quick for PV) This is the IEEE 519-1992 flicker curve, but with two new adjusted curves added by NES to conservatively approximate PV flicker thresholds. Adjusted Borderline of Irritation Curve for PV: This curve used/developed by NES represents a conservative modification to the regular IEEE flicker irritation curve. This curve for PV is meant to capture the fact that PV is not square modulation, and is based on cloud ramping rates, and possible LTC interactions causing flicker. IEEE 519-1992 Borderline of Irritation Curve While the IEEE 1453 method based on Pst, Plt is still the most technically robust approach and should allow best results in tight situations, it is the author s view that this adjusted IEEE 519-1992 curve approach shown here can serve as a cruder but easier alternative method to facilitate quick screens. 519 Visibility Curve x 2.0 519 Irritation Curve x 1.25X Adjusted Borderline of Visibility Curves for PV: This curve used/developed by NES represents a conservative modification to the regular IEEE flicker visibility curve. This curve for PV is meant to capture the fact that PV is not square modulation, and is based on cloud ramping rates, and possible LTC interactions causing flicker. IEEE 519-1992 Borderline of Visibility Curve Note that for PV, the regular IEEE 519-1992 curves are generally too conservative from a flicker visibility perspective due to the fact that PV fluctuations are more rounded rather than square. Prepared by Nova Energy Specialists, LLC 17

PV Flicker Experiences Use of IEEE 1453 method is a technically very robust screening methodology for flicker when very accurate threshold levels need to be determined However, a suggested modified GE flicker curve can work well for PV as a conservative tool for simple screening when less accuracy is required It is the author s experience that other voltage problems (LTC cycling, ANSI limits, etc.) related to PV become problematic at lower capacity thresholds than flicker flicker is one of the last concerns to arise Prepared by Nova Energy Specialists, LLC 18

Some DG Fault Current Issues Impact of current on breaker, fuse, recloser, coordination. Affect on directional devices and impedance sensing devices. Increase in fault levels (interrupting capacity of breakers on the utility system) Nuisance trips due to backfeed fault current Distribution transformer rupture issues Impact on temporary fault clearing/deionization Prepared by Nova Energy Specialists, LLC 19

Fault Current Fault Current Fault Currents of Rotating Machines Separately-Excited Synchronous Generator 4-10 times rated current Subtransient Period Envelope Transient Period Envelope Steady State Period Envelope 2 to 4 times rated current Induction Machine 100% 37% Time Transient Time Constant 4-10 times rated current Current Decay Envelope Time Current decays to essentially zero Prepared by Nova Energy Specialists, LLC 20

Fault Current Contributions of Inverters i Pre-fault I rated Fault Current Worst case t Best Case: May last only a few milliseconds (less than ½ cycle) for many typical PV, MT and fuel cell inverters Typical Worst Case: may last for up to the IEEE 1547 limits and be up to 200% of rated current Note: The exact nature and duration of the fault contribution from an inverter is much more difficult to predict than a rotating machine. It is a function of the inverter controller design, the thermal protection functions for the IGBT and the depth of voltage sag at the inverter terminals. In the worst case if fault contributions do continue for more than ½ cycle, they are typically no more than 1 to 2 times the inverter steady state current rating. Prepared by Nova Energy Specialists, LLC 21

Utility DG Utility Fault Current Impacts: Nuisance trips, fuse coordination issues, transformer rupture issues, etc. 115 kv 13.2 kv Fault Contribution from DG Might Trip The Feeder Breaker and Recloser (Nuisance trip) Adjacent Feeder Fault Case 1 I utility I DG Recloser A The good news is that PV is much less likely than conventional rotating DG to cause issues since inverter fault contributions are smaller! Transformer Rupture Limits (fault magnitude) Fault Case 3 Fault Case 2 DG DG Fault Contribution from DG Might Interfere with Fuse Saving or Exceed Limits of a Device Recloser B Prepared by Nova Energy Specialists, LLC 22

The Author s Experiences Related to PV Fault Levels In doing many projects, I have observed that fault current problems associated with PV in most cases are not an issue due to the low currents injected by the inverter (about 1-2 per unit of rating). In general, only the largest PV (or large PV aggregations) can cause enough fault current to even begin to worry current impacts (there are some special exceptions). As PV capacity grows on a circuit, voltage problems usually arise well before fault currents become an issue. A circuit without voltage problems is not likely to have fault current problems due to PV. Prepared by Nova Energy Specialists, LLC 23

Unintentional DG Islanding Issues Incidents of energized downed conductors can increase (safety) Utility system reclosing into live island may damage switchgear and loads Service restoration can be delayed and will become more dangerous for crews Islands may not maintain suitable power quality Damaging overvoltages can occur during some conditions Adjacent Feeder Islanded Area 115 kv 13.2 kv Recloser A Recloser B (Normally Open) The recloser has tripped on its first instantaneous shot, now the DG must trip before a fast reclose is attempted by the utility Prepared by Nova Energy Specialists, LLC 24 DG

Islanding Protection Methods of DG Passive Relaying Approach (Voltage and frequency windowing relay functions: 81o, 81u, 27, 59 if conditions leave window then unit trips) Active Approach (instability induced voltage or frequency drift coupled and/or actively perturbed system impedance measurement or other active parameter measurement) (UL-1741 utility interactive inverters) Communication Link Based Approach (use of direct transfer trip [DTT] or other communications means) Prepared by Nova Energy Specialists, LLC 25

Islanding and PV Inverters Inverters typically have very effective active antiislanding protection. Unfortunately, the IEEE 1547 and UL-1741 islanding protection requirements (2 second response time) are not compatible with high speed utility reclosing practices used at many utilities If minimum load is nearly matched to generation then provisions such as DTT and/or live line reclose blocking may be needed, especially with high speed reclosing situations. Prepared by Nova Energy Specialists, LLC 26

Screening for Islanding Issues No No No Start Is the DG equipped with at least passive relayingbased islanding protection? Yes Is the reclosing dead time on the Islandable section 5 seconds? Yes Is the annual minimum load on any Islandable section at least twice the rated DG capacity? No Is the DG an Inverter Based Technology Certified Per UL1741 Non-IslandingTest? Yes Yes No Is the mix of (number of and capacity) inverters and other converters and capacitors on the Islandable section within comfortable limits of the UL1741 algorithms? Islanding Protection May Need Careful Examination and Possible Enhancement Yes Islanding Protection is Adequate Prepared by Nova Energy Specialists, LLC 27

Ground Fault Overvoltage V(t) Voltage swell during ground fault Phase A Phase B X 1, X 2 R 1, R 2 X 1, X 2 R 1, R 2 (t) Source Transformer (output side) Phase C X 1, X 2 R 1, R 2 Fault V cn V bn V an X 0 R 0 Ground Fault Overvoltage can result in serious damaging overvoltage on the unfaulted phases. It can be up to roughly 1.73 per unit of the pre-fault voltage level. V cn Before the Fault Neutral Neutral and earth return path V an V bn Neutral V cn During the Fault V an Voltage Increases on V an, V bn V bn Prepared by Nova Energy Specialists, LLC 28

IEEE Effective Grounding Effective grounding is achieved when the source impedance has the following ratios: R o /X 1 < 1 X o /X 1 < 3 V an Voltage includes 5% regulation factor Effective grounding limits the L-G voltage on the unfaulted phases to roughly about 1.25-1.35 per unit of nominal during the fault Effectively grounded system N N ideally grounded system With ungrounded source, the voltage could be as high as 1.82 per unit. V cn N Ungrounded system 1.82 V LN V bn Prepared by Nova Energy Specialists, LLC 29

Generator Step-Up Transformer Grounding Issues High Voltage Side (to Utility Distribution System Primary) Distribution Transformer Low Voltage Side (DG facility) Acts as grounded source feeding out to system Neutral wye delta C C Gen. A B N Neutral grounding of generator on low side of transformer does not impact grounding condition on high side Acts as grounded source feeding out to system only if generator neutral is tied to the transformer grounded neutral Neutral wye wye C C Gen. A B N *IMPORTANT: Generator neutral must be connected to the neutral/ground of the transformer to establish zero sequence path to high side Acts as ungrounded source feeding out to system only if generator neutral is not connected to transformer grounded neutral* Neutral wye wye C C Gen. A B N *neutral is not connected then the source acts as an ungrounded source even though transformer is grounded-wye to grounded-wye Prepared by Nova Energy Specialists, LLC 30

Generator Step-Up Transformer Grounding Issues Continued High Voltage Side (to Utility Distribution System Primary) Distribution Transformer Low Voltage Side (DG facility) Acts as ungrounded source feeding out to system delta delta C C Gen. A B N Neutral grounding of generator on low side of transformer does not impact grounding condition on high side No connection to Transformer Neutral Acts as ungrounded source feeding out to system Neutral Floating Neutral wye delta C C Gen. A B N Neutral grounding of generator on low side of transformer does not impact grounding condition on high side Acts as ungrounded source feeding out to system A Gen. delta wye C N Neutral grounding at generator C on low side of transformer does B not impact grounding condition on high side Prepared by Nova Energy Specialists, LLC 31

PV Inverter Neutral Is Typically Not Effectively Grounded Three Phase Inverter with Internal Isolation Transformer all inside an enclosure a typical arrangement C Wye Delta A B Neutral Terminal Wye has high resistance neutral grounding or is essentially ungrounded Enclosure bond to safety ground 12,470V Utility Distribution Transformer A 480V Neutral B C Building Neutral Safety Ground 277V Usually bonded to earth ground at main service panel per NEC but this does not make it effectively grounded if inverter transformer is not so Prepared by Nova Energy Specialists, LLC 32

Ground Fault Overvoltage Issues Utility System Bulk Source Subtransmission source transformer acts as grounded source suppressing ground fault overvoltage on subtransmission until subtransmission breaker opens. Substation transformer acts as grounded source with respect to 12.47 feeder suppressing ground fault overvoltage on distribution until feeder breaker opens. But it acts as an ungrounded source when feeding backwards into subtransmission! DG Subtransmission Breaker Subtransmission (46kV) Ground Fault Distribution Substation Distribution Substation Feeder Breaker DG Site 1 Ground Fault Transformer Acts as ungrounded source (not effectively grounded) 12.47 kv Line DG Site 2 Transformer acts as ungrounded source or acts as high Z grounded source (if generator neutral is not grounded or high z grounded) DG Load Distribution Substation Load Load Load Neutral is Ungrounded or High Z Grounded Load Need enough load on this island with respect aggregate DG at distribution level to suppress overvoltage otherwise effective grounding or other solutions are needed! Need enough load on this island with respect aggregate DG at all connected distribution substations to suppress overvoltage otherwise special solutions are needed! Prepared by Nova Energy Specialists, LLC 33

Solutions to Ground Fault Overvoltage (any one of these alone will work) Effectively ground the DG if possible (But be careful since too much effectively grounded DG can desensitize relaying and cause other issues. Also, see note 1 with regard to subtransmission impacts of distribution effective grounding of DG.) If DG is not effectively grounded make sure to maintain a minimum load to aggregate generation ratio >5 for rotating DG and >3 for inverter generation Don t separate the feeder from the substation grounding source transformer until sufficient non-effectively grounded DG is cleared from the feeder (e.g. use a time coordinated DTT method.) Use grounding transformer banks at strategic point(s) on feeder. Note 1: On subtransmission since the distribution substations usually feed in through delta (high-side) windings, effective grounding of DG at the distribution level does not make it effectively grounded with respect to subtransmission level. Prepared by Nova Energy Specialists, LLC 34

How Load Reduces Ground Fault Overvoltage V cg Neutral V ag Before the Fault V bg Neutral V cg =0 V ag Voltage Increases on V ag, V bg During Ground Fault (light load) V bg X R For inverters the excessive load will also trigger fast shutdown to protect transistors Impedance of DG Source, its transformer and connecting leads V ag During Ground Fault (heavy load) 12.47 kv Feeder V cg =0 Neutral V bg Utility Source Open Breaker Load Ground Fault (phase C) Voltage does not rise much on V ag, V bg because the overall size of the triangle has been reduced (phase to phase voltage has dropped) Prepared by Nova Energy Specialists, LLC 35

Grounding Transformer Impedance Sizing Utility Source Open X t =5% X 1PV = 30% IEEE Effective Grounding Definition Utility Primary Feeder Grounding Transformer Bank X 0groundbank, R 0groundbank Inverter Assume inverter X 1 is 30% for generic worst case 30% is not the actual impedance since the inverter impedance varies due to controller dynamics and operating state. But 30% is a conservative number that factors worst case conditions whether the inverter is a current controlled or voltage controlled PV source. A higher number can be used for some inverters, but care should be exercised if using a higher value (especially if it exceeds 50%). X R X R 0groundbank X 1pv 0groundbank X 1pv 0groundbank X 1pv 0groundbank X 1pv 3 1 Engineering Targets to Provide Effective Grounding with Reasonable Margin 2 0.7 Prepared by Nova Energy Specialists, LLC 36

Ground Transformer Sizing/Rating Must be sized such that: X0/X1 and R0/X1 ratios are satisfied with some margin (see the targets prior slide) Bank must be able to handle fault currents and steady state zero sequence currents without exceeding damage limits Bank must not desensitize the utility ground fault relaying or impact ground flow currents too much Bank may need alarming or interlock trip of DG if bank trips off. Utility Source Path I 0 utility I 0 Total I 0 Ground transformer Grounding Transformer Path Zero Sequence Current Divider Prepared by Nova Energy Specialists, LLC 37

Ferroresonance and Load Rejection Overvoltage with DG Conditions to Avoid: Islanded State (Feeder Breaker open) Generator Rating > minimum load on island Excessive Capacitance on island Reliable and fast anti-islanding protection that clears DG from line before island forms is a good defense against this type of ferroresonant condition! Reasonably high MLGR avoids it too. EMTP Simulation of Ferroresonant Overvoltage Unfaulted Phase Voltage Normal Voltage Waveform shown is Rotating Machine Type Overvoltage Load rejection, ground fault and resonance related overvoltage Breaker Opens (island forms) Prepared by Nova Energy Specialists, LLC 38

Outcomes of PV Projects (0.1 to 5 MW) the Author Has Been Involved With in Various Locations Type of Issue Voltage Regulation Interactions Fault Current Interactions Islanding Interactions Ground Fault Overvoltage Harmonics Other Typical Experience (over 30 projects studied) Most have not required changes to the regulator or regulation settings and no special mitigation. A few projects have required regulator setting changes to reduce the chance of LTC cycling or ANSI C84.1 voltage violations. The largest sites studied are considering reactive compensation to mitigate LTC cycling and voltage variations. No sites except one caused enough additional fault current to impact coordination or device ratings in a significant manner. For islanding protection, roughly 1/3 rd of the sites have required something special beyond the standard UL-1741 inverter with default settings. Some required more sensitive inverter settings or adjustments to utility reclosing dead time. A few have needed a radio based or hardwired DTT and/or live line reclose blocking added. About 1/3 rd of the sites need some form of mitigation usually a grounding transformer bank, a grounded inverter interface, or a time coordinated DTT No sites have required any special provisions for harmonics yet Some sites are considering operating in power factor mode producing VARs to provide reactive power support. One site had a capacitor concern. Prepared by Nova Energy Specialists, LLC 39

Conclusions PV and other types of DG today are being successfully interconnected on distribution feeders all over the country. In many cases the impacts are not enough to cause worrisome effects. However, the size of projects is growing, especially now that many large commercial and FIT type projects are being considered at the distribution level. Also, the ongoing aggregation effects as PV becomes more widely adopted is leading to more substantial impacts. Many projects can still be screened using simple methods, but increasingly, more detailed analytical methods are becoming necessary. Prepared by Nova Energy Specialists, LLC 40

Conclusions (continued) The relative size of the PV (or DG) compared to the power system to which it is connected plays the key role in system impact effects. Key factors that gauge the relative size include: The MLGR, FRF (SCCR), Stiffness Factor, and GSIR The ratios will usually need to be gauged based on aggregate DG in a zone or region of concern The settings of utility voltage regulation equipment and feeder overcurrent devices and system designs also play a key role. The absolute size and project class (e.g. FIT, net metered) play a role only in that this impacts the scope and criticality of the project and may trigger certain regulatory requirements. Prepared by Nova Energy Specialists, LLC 41