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DISTRIBUTION IMPACT STUDY
(DIS) GUIDELINE Guideline for Studying the Impact of Rooftop PV-Systems on Distribution Networks in the Philippines
www.renewables-made-in-germany.com
Imprint
Authors
Moeller & Poeller Engineering (M.P.E.) GmbH
December 2013 (Version 1)
Publisher
Deutsche Gesellschaft für Internationale Zusammenarbeit (GIZ) GmbH
On behalf of the
German Federal Ministry of Economic Affairs and Energy (BMWi)
Contact
Deutsche Gesellschaft für Internationale Zusammenarbeit (GIZ) GmbH
Köthener Str. 2, 10963 Berlin, Germany
Fax: +49 (0)30 33 84 24 22 253
Email: [email protected]
Web: www.giz.de/projektentwicklungsprogramm
Web: www.renewables-made-in-germany.com
This guideline is part of the Project Development Programme (PDP) South-East Asia. PDP South-East Asia is implemented by the Deutsche Gesellschaft für Internationale Zusammenarbeit (GIZ) GmbH on behalf of the German Federal Ministry of Economic Affairs and Energy (BMWi) under the “renewables – Made in Germany” initiative. More information about PDP and about renewable energy markets in South-East Asia can be found on the website www.giz.de/projektentwicklungsprogramm.
This publication, including all its information, is protected by copyright. GIZ cannot be liable for any material or immaterial damages caused directly or indirectly by the use or disuse of parts. Any use that is not expressly permitted under copyright legislation requires the prior consent of GIZ.
All contents were created with the utmost care and in good faith. GIZ assumes no responsibility for the accuracy, timeliness, completeness or quality of the information provided.
i
Content
1 Background 1
1.1 Purpose of this Document 1
1.2 Application Process 1
2 PV-Inverters 3
2.1 Technology 3
2.2 Requirements of the Technical Interconnection Rules according to the Net-Metering Standard 3
2.3 Technical Characteristics of PV-Inverters 5
3 Distribution Impact Studies (DIS) – Technical Scope 5
3.1 Technical Scope according to the Distribution Code 5
3.2 Impact on Thermal Component Ratings and Voltage Variations on LV-feeders 6
3.2.1 General Study Methodology 6
3.2.2 Example 6
3.3 Impact on Thermal Component Ratings and Voltage Variations on LV-feeders 9
3.4 Coordination of Protection System 10
3.5 Harmonic Performance 10
3.6 Flicker 12
References 13
ii
List of Figures
Figure 1: Workflow of Application Process (taken from [4]) 2
Figure 2: DC-Source with Inverter 3
Figure 3: Load Profile, PV-profile (1kWp), Residual Load Profile 6
Figure 4: Load Profile, PV-profile (4kWp), Residual Load Profile 7
Figure 5: Load Profile, PV-profile (6kWp), Residual Load Profile 7
Figure 6: Example of a LV-feeder with PV generation 8
Figure 7: Residual Feeder Load for different PV-injection scenarios 8
Figure 8: Voltage at the end of the LV-feeder for different PV-injection scenarios 9
Figure 9: Example of a LV-feeder with PV generation 11
Measurement
W Watt Wp Watt peak Wh Watt hour
kW Kilowatt kWp Kilowatt peak kWh Kilowatt hour
MW Megawatt MWp Megawatt peak MWh Megawatt hour
GW Gigawatt GWp Gigawatt peak GWh Gigawatt hour
iii
List of Acronyms
DAS Distribution Assets Study
DIS Distribution Impact Study
DSOAR Distribution Service and Open Access Rules of the Philippines
DU Distribution Utility
IGBT Insulated-gate bipolar transistor
IGCT Integrated gate-commutated thyristor
LV Low Voltage
MV Medium Voltage
PV Photovoltaics
QE Qualified End Unser
TDD Total Demand Distortion, THD of current
THD Total Harmonic Distortion
VDE German Association for Electrical, Electronic and Information Technologies
DISTRIBUTION IMPACT OF ROOFTOP-PV
1
1 Background
1.1 Purpose of this Document
On 27 May 2013, the Energy Regulatory Commission adopted ERC Resolution 09, Series of 2013 approving the
Rules Enabling the Net-Metering Program for Renewable Energy. This resolution was published on 10 July 2013 in
newspapers of general circulation in the country and took effect 15 days thereafter. Thus, the Net-Metering Rules
took effect in the Philippines on July 24, 2013.
Net-metering allows customers of Distribution Utilities (DUs) to install an on-site Renewable Energy (RE) facility
not exceeding 100 kilowatts (kW) in capacity so they can generate electricity for their own use. Any electricity
generated that is not consumed by the customer is automatically exported to the DU’s distribution system. The DU
then gives a peso credit for the excess electricity received equivalent to the DU’s blended generation cost, excluding
other generation adjustments, and deducts the credits earned to the customer’s electric bill.
As part of the technical evaluation the DU has the option to perform a Distribution Impact Study (DIS) to
assess the ability of the Distribution system to safely and reliably accommodate a proposed interconnection of a
generation source and if any upgrades may be required.
This document will:
Define a guideline for the typical scope of DIS for Renewable Generators that will be connected under a
Net-Metering Agreement.
Define criteria allowing a decision whether DIS will be required or not.
The guidelines presented in this document are mainly based on international practice for the connection of
renewable generation to LV networks and propose simplified methods for reducing time and effort needed for
determining the impact of renewable generators on LV networks.
1.2 Application Process
The Application Process for Renewable Generators that shall be connected to LV-networks of the Philippines is
defined in the Net-Metering-Rules [1] and further explained in [4].
It covers the whole process, starting from a written request for receiving information and data required for the
submission of an application and ends with the signature of a connection agreement (see Figure 1).
This application process further defines that the Distribution Utility (DU) shall decide whether the execution of a
Distribution Impact Study (DIS) and/or a Distribution Assets Study (DAS) shall be required in accordance with the
Distribution Service and Open Access Rules of the Philippines (DSOAR) [2].
The DSOAR [2] further specify the purpose of DIS and DAS:
A DIS shall identify whether any distribution constraints, re-dispatch options, additional dedicated
Connection Assets, or Distribution System upgrades shall be required to provide the requested service.
Based on the results of a DIS, a DAS shall be executed with the purpose of identifying in detail additionally required
distribution assets and corresponding costs.
According to DSOAR [2], a DIS is always executed by the Distribution Utility (DU), whereas a DA can either be
executed by the applicant itself or the DU. The Net-Metering rules [1] do not explicitly mention the possibility that a
DAS can be executed by a Net-Metering applicant.
The costs of a DIS and a DAS always have to be covered by the applicant.
The Philippine Distribution Code [3] specifies the scope of DIS as follows:
The Distributor shall conduct Distribution Impact Studies to evaluate the impact of the proposed
connection or modification to an existing connection on the Distribution System. The evaluation shall
include the following:
o Impact of short-circuit infeed on the distribution equipment
o Coordination of Protection System
o Impact of User Development on Power Quality
The Distributor may disapprove an application for connection or a modification to an existing connection
to the Distribution System if it is determined through the Distribution System Impact Studies that the
proposed connection or modification will result in the degradation of the Distribution System.
Figure 1: Workflow of Application Process (taken from [4])
When comparing the definition of DIS in the DSOAR [2] and the Distribution Code [3] a slight difference with
regard to the purpose of DIS can be noticed:
DISTRIBUTION IMPACT OF ROOFTOP-PV
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According to DSOAR, a DIS has to be carried out for identifying required network upgrades, which in turn
will avoid any degradation of the performance of the distribution system, whereas
According to the Distribution Code, the result of DIS will be used for decide whether a connection will be
permitted or not.
Because the Net-Metering Rules [1] explicitly refer to DSOAR [2] in section 5.5 of [1], it can be assumed that the
result of DIS will be used for defining required distribution network upgrades (through DAS) and not for rejecting
an application without having analyzed potential network upgrades.
2 PV-Inverters
2.1 Technology
Figure 2: DC-Source with Inverter
Photovoltaic (PV) modules produce a DC-voltage and a DC-current that is converted into AC by an inverter. The
connection to the LV feeder is either single phase or three-phase, depending on the size of PV-inverter.
Modern PV inverters are of the voltage source type using self-commutated technologies built by IGBTs or IGCTs.
Because of the high switching frequency of modern inverters, which is in a range of up to 20 kHz, the level of
harmonic current injections is usually very low.
For most system studies, a PV inverter can be modelled by a controlled current source having a defined active and
reactive current response.
Because the output of PV-inverters is fully controllable, relevant aspects such as reactive power control capability or
its response to voltage or frequency disturbances follows the requirements of applicable connection conditions (or
interconnection rules, grid code, etc.).
2.2 Requirements of the Technical Interconnection Rules according to the Net-Metering
Standard
The relevant technical characteristics, as specified by relevant interconnection rules [1] can be summarized as
follows:
Continuous operation in a voltage range of +/-10% and a frequency range of 58,2Hz < f < 61,8Hz
Power Factor: According to [1] there is no power factor control requirement. The only requirement with
regard to power factor is that it must be above cosphi=0,85 lagging during all times. Hence, for distribution
impact studies, it can be assumed that PV-inverters will operate at unity power factor.
During Voltage Disturbance, a PV inverter must remain connected for voltage dips down to a retained
voltage of zero for 150ms. For retained voltages between 30% of nominal voltage and 90% of nominal
voltage a linear interpolation between 600ms and 3 s applies.
There is no requirement with regard to the actual behavior of PV-inverters during a voltage dips specified
in [1].
However, it is recommended to require from PV-inverters either:
o to set their current (active and reactive current) to a value equal to zero or
o at least not to increase their current above the pre-fault value.
If PV-inverters behave during voltage dips according to such a requirement, their impact on short circuit
levels and feeder-protection selectivity can be neglected.
Because PV-inverters have very fast current control capability, they are able to comply with such
requirements.
Power Quality:
o DC-currents: According to the Net-Metering Rules [1], DC-currents must not exceed 0,5% of the
full load rated current of the inverter. Such requirement must be verified by type tests of PV-
inverters. It is not further relevant to Distribution Impact Studies.
o Flicker Severity: With regard to Flicker, the Net-Metering Rules [1] refer to section 3.2.6 of the
Distribution Code [3] and must not exceed a short-term flicker severity limit of Pst=1 and Pst=0,8
at the connection point of any user in the system.
This requirement relates to voltage flicker at the connection point of any User (generation or load)
in a distribution network and is hence a result of:
Background Flicker at the MV-station feeding the LV-feeder of interest.
All flicker sources (loads and generators) in the LV-feeder of interest.
o Harmonics: With regard to harmonic distortion, the Net-Metering Rules [1] make reference to
section 3.2.4 of the Distribution Code [3]. According to this, there are two harmonics
requirements to comply with:
THD of voltage no greater than 5% at the connection point of any user in the system.
TDD (Total Demand Distortion, THD of current) of any User System shall be no greater
than 5% during normal operation.
Because harmonic voltage is a result of:
Background harmonics at the MV-station feeder the LV-feeder of interest.
Harmonic current injections of all Users (load and generation) in the LV-feeder of
interest.
Harmonic voltage distortion must be studied considering a complete feeder.
The second criterion however (TDD of current no greater than 5% of rated full load current) is a
device-specific property and must be verified using type tests of PV-inverters.
Voltage Unbalance: The Net-Metering Rules [1] don’t address voltage unbalance explicitly but because
of the general reference to the Distribution Code, it can be assumed that section 3.2.5 of the Distribution
Code [3] also applies to Net-Metering Devices.
This section states that voltage unbalance, which is defined by the maximum deviation of the three phase
voltages from the average of the three phase voltages rated to the average of the three phase voltages shall
not exceed 2.5%.
This requirement is important for the definition up to which size single phase inverters will be permitted.
DISTRIBUTION IMPACT OF ROOFTOP-PV
5
2.3 Technical Characteristics of PV-Inverters
Technical characteristics of PV inverters are very flexible and mainly follow corresponding specifications.
The main characteristics of PV-inverters are:
Can operate at a defined power factor (by default: cosphi=1)
Low harmonics contents because of high switching frequencies
Low impact on flicker
Low DC-current injections
Input data for PV-inverters can be obtained for type-tested or even certified inverters, e.g. inverters certified
according to the German VDE-standard [4] or according to IEC61727 [6]. In some cases, power quality
characteristics of PV-inverters are tested according to IEC61400-21, which has been developed for wind turbine
generators but whose power quality test procedures are also applicable to PV-inverters.
Such type tests or measurements should contain the following type of information relating to PV-inverters:
Table of worst-case harmonic current injections (per frequency)
Flicker step-change factor kf (in function of active power output and network impedance angle)
Flicker voltage-factor ku (in function of active power output and network impedance angle)
Continuous flicker coefficient c (in function of active power output and network impedance angle)
Level of DC-current injections
These data can directly be used for carrying out corresponding Distribution Impact Studies (DIS).
3 Distribution Impact Studies (DIS) – Technical Scope
3.1 Technical Scope according to the Distribution Code
The Distribution Code [3] defines the following technical scope of Distribution Impact Studies (DIS):
Impact of short-circuit infeed on the distribution equipment
Coordination of Protection System
Impact of User Development on Power Quality
However, for identifying required feeder reinforcements, this list of technical studies should be extended as follows:
Studies relating to thermal component ratings
Studies relating to voltage variations (especially Long Duration Voltage Variations according to the
definitions of the Distribution Code).
These load flow studies of the relevant area of a distribution grid will identify the need for network reinforcements
such as reinforced lines or cables, additional lines/cables or a replacement of a distribution transformer and should
be carried out prior to power quality studies for ensuring that the impact of component upgrades will be covered by
all subsequent impact studies.
3.2 Impact on Thermal Component Ratings and Voltage Variations on LV-feeders
3.2.1 General Study Methodology
Studies relating to thermal component ratings and voltage variations are mainly relevant if there are times during
which a PV system produces considerably more power than the corresponding load absorbs. As long as PV-
production is below the maximum demand of the corresponding load, the PV production will only reduce line/cable
loadings and voltage drops but not increase it. Only in cases, in which the production of a PV-system starts
exceeding the associated load, a voltage rise or increased thermal loading of lines or cables can be observed.
According to the Distribution Code [3] voltage in distribution grids (MV and LV) may vary between +/-10% of the
rated voltage.
With regard to voltage variation studies in a LV-feeder with distributed generation this means that distribution
system impact studies must consider the following two worst case scenarios:
Case 1: Min. voltage at MV-bus bar, max. load and no generation.
Case 2: Max. voltage at MV-bus bar, min. load (during day-time) and max. generation.
With regard to Case 2 (min. load) it has to be considered that min. load often occurs during night-time, when there
is no PV generation. Hence, it is important to consider a “min. load during day time” condition. In case of
residential loads, this “min. load during day-time” usually occurs on working-days, when people are out for work.
In case of commercial loads, this situation typically occurs on week-ends.
With regard to max./min. voltages at the feeding MV-bar, the typical voltage limits of operation should be applied
(e.g. +/- 5%). These limits are usually chosen in a way that there is sufficient room for additional voltage drops (or
voltage rises) on the LV-feeder.
For studying the impact of PV installations on thermal component ratings and voltage variations, the following
steps should be executed:
Define the relevant worst case operation scenarios
Execute a load flow study for the two worst case operation scenarios
Evaluate maximum thermal loading and max. voltage rise on the feeder.
Decide whether grid reinforcements or a direct transformer connection will be required.
3.2.2 Example
Figure 3: Load Profile, PV-profile (1kWp), Residual Load Profile
DISTRIBUTION IMPACT OF ROOFTOP-PV
7
Figure 4: Load Profile, PV-profile (4kWp), Residual Load Profile
Figure 5: Load Profile, PV-profile (6kWp), Residual Load Profile
For illustrating the relationship between load and PV generation, Figure 3, Figure 4 and Figure 5 show load profile,
generation profile and residual load profile of a residential load and a PV installation with 1kWp, 4kWp and 6kWp
respectively.
These figures show that:
During most times, residual load is considerably reduced compared to the actual load
The peak of residual load remains almost unchanged compared to peak load
The worst case export situation occurs during mid-day, when PV generation is high and the load has a local
minimum.
For illustrating the impact of PV-generation on feeder load and voltage profile, the example of a simplified LV-
feeder according Figure 6 is used.
The load profiles of this example correspond to the load profile depicted in Figure 3, Figure 4 and Figure 5.
The peak load of the feeder is equal to Smax=kVA at a power factor of cosphi=0,95.
The following four scenarios with regard to PV-injection are studied:
Case 1: No PV generation
Case 2: Low PV generation, PVmax=11kWp
Case 3: High PV generation, PVmax=44kWp
Case 4: Very high PV generation, PVmax=88kWp
The results according to Figure 7 (residual feeder load) and Figure 8 (voltage profile) show the following:
The worst case export scenario occurs during mid-day, confirming the worst case assumption stated in
section 3.2.1.
Only if PV generation exceeds the feeder load, leading to a reverse power flow on the feeder, there will be a
voltage rise across the feeder.
In this case, maximum voltage rise occurs during maximum PV generation and minimum day-time load.
Maximum voltage drop across the feeder is almost not influenced by PV generation (assuming that peak
load occurs in the evening).
This example confirms the general methodology described in section 3.2.1.
Figure 6: Example of a LV-feeder with PV generation
Figure 7: Residual Feeder Load for different PV-injection scenarios
DISTRIBUTION IMPACT OF ROOFTOP-PV
9
Figure 8: Voltage at the end of the LV-feeder for different PV-injection scenarios
3.3 Impact on Thermal Component Ratings and Voltage Variations on LV-feeders
According to the published version of the Net-Metering rules [1], PV inverters must remain connected for at least
150ms in the case of a solid fault on an LV-feeder. With regard to the response of a PV-inverter to such a voltage
dip, no detailed specification is given in [1].
It is therefore recommended to require form PV-inverters one of the following types of behavior during grid faults:
“Zero current mode”: Reduction of current (active and reactive current) to zero if voltage drops below the
continuous limit of operation (90%).
“Pre-fault current”: If voltage drops below the continuous limit of operation (below 90%), it is not
permitted that the current exceeds its pre-fault value.
In both cases, there will be no considerable short circuit infeed of PV-inverters and hence no considerable impact
on Distribution Equipment and not short circuit studies will be required as part of DIS for PV-connections to LV-
feeders.
However, in the case that no such requirement will be put in place, it has to be assumed that PV-inverters will
deliver up to their maximum current capability during a voltage dip. This maximum (short-term) current capability
must be obtained from the data sheet of each converter type.
In the absence of any reliable information relating to this aspect it can be assumed that the maximum short-term
current of a PV-inverter does not exceed a value of
Imax=1,3 Irated
It must further be considered that this short circuit feed-back is a result of a current limit of a controller and hence
not a function of any impedance between PV-inverter and fault location.
Unfortunately, no internationally accepted standard for short circuit calculation (IEC60909 or ANSI C37) is able to
consider this type of current source behavior. Therefore, the following procedure is recommend;
Step 1: Calculate the short circuit current according to IEC60909 or ANSI C37 ignoring short circuit infeed
from PV-inverters (considering grid-infeed only)
Step 2: Add the sum of the maximum possible short circuit infeed of all PV-inverters in the analyzed LV-
feeder to the grid-infeed for obtaining the resulting short-circuit current at each node in the LV-feeder.
Verify the short circuit rating of all components.
In other words, the maximum expected increase of short circuit current in a LV feeder can be estimated by the total
maximum short-term current of all PV-inverters in the feeder.
3.4 Coordination of Protection System
In the case that a generator operates either in “Zero Power” or “Pre-fault Current” Mode, the impact of a PV-
inverter on protection selectivity can be neglected because there is no considerable short-circuit contribution of a
PV-inverter.
In the case that no such additional requirement exists, the impact of back-feed from all PV inverters connected to a
LV-feeder has to be evaluated and settings of protection relays, LV-circuit breakers and trip levels of fuses have to
be re-assessed.
Because of the complexity of this task it is generally recommended to require “Zero Power” Model behavior during
grid faults.
3.5 Harmonic Performance
According to the Net-Metering Rules [1] there are two requirements with regard to harmonics:
Harmonic Current distortion must not exceed a TDD of 5% (THD of current)
Harmonic Voltage distortion must not exceed a THD of 5% at the connection point of any User.
The assessment of the current distortion criterion doesn’t require any system impact study because this is a device-
specific value.
The assessment of harmonic voltage distortion however requires studies, if it shall be evaluated prior to a
connection (and not only based on measurements, after commissioning of the PV system).
It is therefore recommended to carry out harmonic voltage distortion studies in order to assess whether the
allocated harmonic currents will result in a limitation of PV installations or not.
The methodology of such a study could be based on the following steps:
Define harmonic planning levels at the feeding MV node (harmonic background level LMV(h))
Define the maximum global harmonic voltage contribution of loads in the LV feeder (Gload(h))
Define a reasonable maximum PV allocation scenario in the LV feeder (total installed PV-capacity per LV-
node)
Calculate for each node the relevant upstream impedance (network impedance at each node Zup(h)) and the
total harmonic current injection (IPV(h)) resulting from all downstream PV installations by applying
summation law 2 according to IEC61000-3-6.
Calculate the global harmonic voltage contribution of all downstream PV inverters for each node.
DISTRIBUTION IMPACT OF ROOFTOP-PV
11
Calculate harmonic voltage distortions and THD at the first node in the LV feeder (node “1” in Figure 9)
using the following parameters:
o Harmonic planning level of upstream grid LMV(h)
o Maximum global harmonic voltage contribution of LV-loads: Gload(h)
o Calculate global harmonic voltage contribution of all downstream PV inverters: GPV(h)
o Calculate harmonic voltage U1(h)
o Calculate THD at node “1”
Calculate harmonic voltage distortion and THD at all other nodes in the feeder recursively
With regard to harmonic planning levels and global harmonic voltage contribution of LV-loads, Table 1 of
IEC61000-3-6 could be referred and scaled appropriately.
Figure 9: Example of a LV-feeder with PV generation
The formulas required for calculating the above listed parameters for each node are the following:
Calculation of total harmonic current injection resulting from all downstream PV installations:
n
i
down hIhIi
11
)()(
Calculation of global harmonic voltage contribution of downstream PV inverters:
)()()( 111 hIhZhG downPV
Calculation of harmonic voltage:
)()()()( 121 hGhGhLhU PVload
Calculation of THD at node 1:
n
n
h
U
hU
THD 2
1
1
)(
Recursive calculation of harmonic voltage distortions at other nodes in the feeder:
21212 )()()( downPVPV IhZhGhG
with:
n
i
down hIhIi
22
)()(
and
)()()()( 222 hGhGhLhU PVload
The summations are based on a superposition of harmonic voltages according to summation law II/IEC61000-3-6
[8].
The coefficient is defined as follows:
h<5 =1
5<=h<=10 =1,4
h>10 =2
For harmonic current injections of PV-inverters, harmonic currents according to IEC61727, which are in-line with a
TDD of 5% can be assumed.
The load contributions Gloadi can be allocated or calculated analogously to the PV-contributions on basis of
harmonic load-current injections.
Much easier than an application of the above formulas (e.g. using EXCEL spreadsheets) would be the use of a
power system analysis software that supports harmonic analysis according to IEC61000-3-6, summation law 2,
directly.
3.6 Flicker
As stated in section 3.2, the impact of PV-inverters on flicker is generally low because a PV-inverter does not
represent a considerable flicker source, as long as the controller of the PV-inverter is properly tuned.
Therefore, it should be sufficient to carry out type tests of PV-inverters or only use inverters that are certified
according to IEC61727 [6]
System-wide studies for calculating flicker levels at all nodes will then not be required.
DISTRIBUTION IMPACT OF ROOFTOP-PV
13
References [1] Republic of the Philippines – Energy Regulatory Commission: A Resolution Adopting the Rules Enabling
the Net-Metering Program for Renewable Energy, Resolution No. 09, Series of 2013
[2] Republic of the Philippines – Energy Regulatory Commission: Distribution Services and Open Access
Rules (DSOAR), ERC Case No. 2005-10RM, 18.01.2006
[3] Republic of the Philippines – Energy Regulatory Commission: Philippine Distribution Code, December
2001
[4] Deutsche Gesellschaft für Internationale Zusammenarbeit (GIZ) GmbH on behalf of the German Federal
Ministry of Economic Affairs and Energy: Manual for Interconnection – Report for supporting the
interconnection of Rooftop-PV-Systems in the Philippines, www.exportinitiative.de
[5] VDE-AR-N 4105 :2011-08: Power generation systems connected to the low voltage distribution network –
Technical minimum requirements for the connection to and parallel operation with low voltage distribution
networks, VDE, 2011
[6] IEC61727: Photovoltaic (PV)-systems - Characteristics of the utility interface, Second Edition, 2004
[7] IEC61400-21: Wind turbines – Part 21: Measurement and assessment of power quality characteristics of
grid connected wind turbines, Edition 2.0, 2008-08
[8] IEC61000-3-6: Electromagnetic compatibility (EMC) – Part 3-6: Limits – Assessment of emission limits
for the connection of distorting installations to MV, HV and EHV power systems
Further information:
Deutsche Gesellschaft für Internationale Zusammenarbeit (GIZ) GmbH on behalf of the German Federal
Ministry of Economic Affairs and Energy: Net-Metering Reference Guide, www.exportinitiative.de
