Bremen Energy Working Papers

Paperseries No. 20
Christine Brandstätt, Gert Brunekreeft, Ken Furusawa,and Toru Hattori

Distribution planning and pricing in viewof increasing shares of intermittent,
renewable energy in Germany and Japan
March 2015

Jacobs University Bremen
Bremen Energy Research (BER)

Editors:
Prof. Dr. Gert Brunekreeft
Dr. Roland Meyer
Jacobs University Bremen
Bremen Energy Research (BER)
Campus Ring 1 / South Hall28759 Bremen
www.jacobs-university.de/
http://b-e-r.user.jacobs-university.de/Contact:
Dr. Roland Meyer
Tel. +49 (0) 421 – 200-4868
E-mail ro.meyer@jacobs-university.de

Suggested citing:
Brandstätt, Chr., Brunekreeft, G., Furusawa, K., and Hattori, T., 2015, “Distribution planningand pricing in view of increasing shares of intermittent, renewable energy in Germany andJapan”, Bremen Energy Working Papers No. 20, Jacobs University Bremen.

The ”Bremen Energy Working Papers” are published by Jacobs University Bremen. The papers
feature research and scholarship of a preliminary nature that should encourage dialogue andcritical discussion. The content does not necessarily reflect the views of Jacobs University
Bremen and is the sole responsibility of the authors. Jacobs University Bremen does not bear
any responsibility concerning the contents.

ii

Distribution planning and pricing in view ofincreasing shares of intermittent, renewableenergy in Germany and Japan
Christine Brandstätta, Gert Brunekreefta, Ken Furusawab, Toru Hattoriba

Jacobs University Bremen, Germany b Central Research Institute of Electric Power Industry, Japancorresponding author: Christine Brandstätt, c.brandstaett@jacobs-university.de
March 2015
Abstract
In response to the global climate challenge many countries are faced with increasing shares of energy
from renewable sources in their power supply. The integration of RES (renewable energy sources)
generation however entails technical as well as institutional challenges for power grids. This study
relies on recent experiences of German distribution network operators in network planning andnetwork pricing and looks at their transferability to Japan.
Distributed generation may cause problems of voltage variation and asset overloading inconventional power grids. Technical solutions for these problems are available and well-known yet
require considerable investments. The study presents regulatory incentives for network operators totake efficient means to maintain supply quality. With distributed generation self-supplying customers
may contribute too little to network cost and new generators and flexible consumers may causesignificant investment by uncoordinated siting and operation. An adequate pricing scheme can serve
to sustainably finance the infrastructure while at the same time giving incentives to coordinate
network users. This study points out options for network charging in grids with high shares of
distributed generation from renewable sources.

1

1 Introduction
A rapid increase in intermittent generation based on renewable energy sources (RES) has been thecause of concern for electricity network planning and operation in the major developed countries
including Germany and Japan. A generous feed-in-tariff scheme in both countries has attracted large
amounts of RES generation facilities. Particularly, we have seen a surge of photovoltaic (PV) facilities
in recent years. These PV plants are usually connected at distribution network level, and distribution
system operators (DSOs) are required to incorporate such a large amount of PV while maintaining
the reliability of the network.
This situation raises a number of technical challenges for the DSOs in their network planning. Unlessthey were allowed to curtail the outputs from PVs at their discretion, they would have to significantly
upgrade the network, which takes a lot of investment. This in turn leads to several economic andregulatory problems. The DSOs are often incentivized to minimize the cost of operating andmaintaining the network as they are usually subject to an overall revenue allowance. Ultimately theywould have to consider the best allocation between operating expenditure (OPEX) and capital
expenditure (CAPEX) to minimize the total cost while integrating RES generation in their network. To
do so, traditional distribution planning and operation may need to be revised to take into accountthe technical problems caused by the massive amount of RES facilities to be developed. In addition,
the role of regulation is important to induce the DSOs to take appropriate actions, and thus theregulators also need to understand the impact of the increasing amount of RES generation on
reliability and the countermeasures to be taken. However, the technical problems actually faced by
the DSOs are not yet well understood.
Another economic problem is the structure of the network tariffs (fixed charges versus usage-based
charges, with or without time-of-use and locational elements, etc.). A related question would be:
who is paying for what? With the existing tariff structures, DSOs may not be able to generate enoughrevenue to carry out the required investment, and also give wrong economic signals to the network
users, which may eventually lead to inefficient network development. The issue has been recognizedand discussed in the industry as well as academia in Europe1. The current practices of network pricing
at European DSOs are not well known. Thus, it is hard to evaluate the difficulties associated withdesigning an optimal tariff structure and the potential for improvement.
The transfer of German experiences to Japan is particularly interesting, as Japan will be going
through a series of market reforms. The purpose of this research is to investigate the potential for
improvement of distribution network planning and structure of the network pricing, given therequirement to connect a large amount of PV generation facilities based on a case study of thecurrent practice of German DSOs. The results of our research would be particularly useful for othercountries including Japan, as they face the problem of a rapid increase in PV installations in many
parts of the country.
The report is organized as follows: the next section provides some background on the increasing
share of intermittent RES generation at distribution network level in Germany and Japan. Section 3
discusses the challenges and possible solutions in distribution planning given the large amount of

1

The issue has been discussed also in the U.S. where the number of PV installations has rapidly increased inrecent years [e.g. Kind 2013]. However, the discussion seems to be at an early stage, yet.

2intermittent RES generation based on international practice with a special reference to Germany.
Section 4 discusses the challenges and possible solutions in network pricing for German utilities, andderives some implications for other countries. Section 5 concludes our discussion and presents future
research topics.

3

2 Background on increasing shares of intermittent RES generationand the electricity sector
2.1 Germany
Germany today has more than 800 local DSOs and 4 transmission system operators (TSOs). All of the
TSOs and the larger DSOs are at least legally unbundled from other stages of the value chain, if noteven in different ownership. However, the requirements for small DSOs with less than 100,000
customers are much weaker. Around 90% of the German DSOs remain integrated with retail and/or
generation. The t pi al Ger a “tadt erk supplies electricity, gas and water while operating therespective networks. Network regulation in Germany is incentive-based and includes a revenue-cap
and a quality element. The process of liberalization and unbundling in Germany dates back to 1998,
when the implementation of the first European directive on common rules for the internal electricity
market started. 2 In recent years a certain level of competition developed in electricity retail. An
average customer can choose between 70 to 90 different suppliers, including suppliers of green
electricity [BNetzA 2014].
Support for RES generation started as early as 1991. The support scheme has changed over the years.
At first there was only a take-off obligation for the network operators and the requirement toconnect renewable generators to the network. With the renewable energy act in 2000 a fixed feed-in
tariff (FIT) was introduced. The guaranteed remuneration for a fixed period of time, for manytechnologies 20 years, boosted the development of RES generation over the years. The development
since 1990 is depicted in Figure 1. With RES generation now supplying about one fourth of the total
electricity consumption, the RES support is now transitioning to a market premium scheme. Existing
plants that were built under the FIT will still continue to receive their fixed remuneration for theperiod set out in the respective laws. Yet new and larger plants under the new support scheme will
only receive a premium on top of the market price for their electricity and will be in charge of selling
their electricity.
GW

hydro

wind

biomassPV

Figure 1: Development of installed RES capacity in Germany [BMWi 2014a]

2

For a more detailed description of the process see Brunekreeft et al. [2014].

4

Today Germany has almost 85 GW of installed RES capacity. Even though the change of support
scheme is meant to slow the development down, the installed capacity will continue to rise in the
future. According to the renewable energy act the share should grow to over 120 GW within the next
15 years and the goals of the single states within Germany would add up to more than 200 GW. Thisdevelopment is predicted to entail a significant amount of network expansion. The additional
investment needed for network expansion due to RES integration will amount to between 23 and 49
illio € in the upcoming 15 years. The yearly estimation is depicted in Figure 2.

illio €
per yearsi gle states goals

renewable energy act

low voltage

medium voltage

high voltage

Figure 2: Yearly additional expenditures for integrating RES generation in distribution grids [BMWi2014b]The prediction of these large investment needs has led to a discussion of measures to reduce theinvestment need, including innovative network operation and innovative network pricing.

2.2 Japan
In Japan, regional electricity distribution networks are owned and operated by ten verticallyintegrated utilities with accounting separation between the network and other competitive
segments. Except for Tokyo Electric Power Co. (TEPCO), they are privately owned companies3. The
electricity retail markets for commercial and industrial customers have been opened up forcompetition since 2000, but the market for residential customers is regulated.
The Great East Japan Earthquake in March 2011 and the nuclear accident at Fukushima Daiichi plantcompelled the government to initiate further reform of the industry. An experts subcommittee onelectric power system reform was organized to discuss the institutional framework for the necessaryreform. In February 2013 the committee submitted the final report that outlined the road map. The
reform proceeds in three stages: the first stage is to facilitate wide area coordination of system
operations by establishing the Organization of Cross-regional Coordination of Transmission
Operation (OCCTO) in 2015. The second stage is to fully liberalize the retail market by allowing retailchoice for residential customers in 2016. The third stage is, although the law was not enacted, to
3

The majority (54.69%) of the share of TEPCO is owned by the government through Nuclear Damage
Compensation and Decommissioning Facilitation Corporation.

5

secure the neutrality of the network by separating the transmission and distribution from verticallyintegrated utilities through legal unbundling.
Historically, the share of intermittent RES generation (not including hydro power generation) has
been low in Japan, only accounting for less than 1% of total generation. A FIT for RES generation was
introduced in 2012. The electric utilities are obliged to connect RES facilities to the network andpurchase all their generated power. The purchase price is considered as generous. For example,
when FIT was introduced in 2012, the purchase price of PV for residential was set to 42 yen per
kWh4, approximately twice the retail price for residential customers. The purchase price has beensubsequently revised and is now somewhat lower. The current prices of PV and wind power are
shown in Table 1.

10kW and overPurchase Price per kWhContract Period

32 yen plus tax
20 years

PV
Less than 10kW
37 yen
10 years(with cogeneration)
30 yen
10 years

Wind
20kW and overLess than 20kW

Offshore

22 yen plus tax
20 years

55 yen plus tax
20 years

36 yen plus tax
20 years

Table 1: Purchase price and contract period for PV and wind under FIT 5 [ANRE 2014]
Such a generous FIT scheme has resulted in a rapid increase in RES generation projects certified by
the government, especially non-residential photovoltaic. Table 2 shows the cumulative capacity inservice as well as capacity certified under FIT by plant types.
(MW, as of September 30, 2104)

Capacity in service
Capcity certifiedPVPV(residential)(non-residential)
7320
10580
3140
65840

Small & Medium
Wind
Hydro
2660
240
1310
330

Geothermal

Biomass
0
10

1220
1350

Table 2: Status of RES facilities under FIT [ANRE 2014]
There are regional differences in the rate of increase in PVs, as shown in Figure 3. For example, in
Kyushu area (southwest part of Japan) served by Kyushu Electric Power Company, if all the capacity
were connected, then the installed amount of capacity would exceed regional peak demand.
In September 2014, Kyushu Electric Power Co. announced to temporarily suspend the review process
for integrating RES generation facilities under FIT, due to the concern about the oversupply of powerfrom PV. By October 2014, five utilities in total (Kyushu, Shikoku, Okinawa, Tohoku, and Hokkaido)
were forced to temporarily suspend the process of integration (that is, putting the requests on hold)for similar technical reasons. Electric utilities had been allowed to curtail RES output from PV or windwith 500kW or more for up to 30 days per year without compensation6. They had to compensate
such RES generators if they curtail after exceeding 30 days per year. These rules were revised in
January 20157. Now the utilities are allowed to curtail all certified facilities if necessary 8, for up to 360
hours for PV per year without compensation (up to 720 hours for wind). RES generators are also
obliged to install remote control system for the curtailment. In the special case that the expected
4

appro i atel
€ e ts per kWh, i Ja uar, e o erts to .
€.
Small gas engines are often offered together with small PV by Japanese gas utilities.
6
A i i u of o e hour of urtail e t is regarded as „o e da .
7
The changes do not apply to facilities whose application for connection was completed before the revision.
8
Facilities with more than 10kW are prioritized.
56amount of RES generation exceeds the capacity limit of the utilities grid, then those utilities canbecome designated utilities who are allowed unlimited curtailment without compensation.
Hokkaido Electric Power Company used to be the only such designated utility but now there are 6
others.
Although a discussion for revision of the FIT scheme is also likely to emerge, a fundamental
reconsideration of network tariff regulation will be required in the future. As of this writing, theregulatory framework for transmission and distribution companies after legal unbundling is not yet
clear.

Figure 3: Status of certified RES facilities by areas of utility in MW9 [ANRE 2014] and [FEPC 2014]9

Data is represe ted u til Ma, Peak De a d is the su
er peak i. Kanto is mainly served by
TEPCO. Chubu is served by Chubu Electric Power Co. and Hokuriku Electric Power Co. Kinki is served by Kansai
Electric Power Co.

7

3 Challenges and possible solutions in distribution planning
3.1 Current system of distribution planning
Currently, the distribution system operator (DSO) makes the network planning taking into
consideration the uncertainties over the next 5-10 years. A typical flowchart of distribution network
planning is shown in Figure 4 [Grond et al. 2013]. The objective function for distribution network
investment planning is usually to minimize the total cost of investment, operation and maintenance,
subject to the technical constraints, including the thermal limit of a line, the range of voltage
deviations, and avoiding energy not supplied. Japanese DSOs (now as a part of the verticallyintegrated utilities) also employ these flowcharts [ESCJ 2014] [TEPCO 2012].

New development

E.g. Network connection of
new customers
or Load growth

Problem definition

E.g. possibility of bottleneck

Classification of uncertainties
Assumption of scenarios

E.g. future load growth

Alternatives & solutions

E.g. network reinforcement,
introduction of FACTs*,
reconfiguration of network

Evaluation of objective function
Check of constraints

E.g. investment cost, O&M cost
E.g. thermal limit, voltage
deviation, short circuit current,
expected not supplied energy

Decision and implementation* FACTs is Flexible AC Transmission system

Figure 4: Flowchart of distribution network planning (own figure based on Gond et al. [2013])
Before the massive introduction of RES generation, the requests for network connection were rather
rare. Therefore DSOs were able to process the requests along this flowchart and did not have muchtrouble with the queue for connection.

3.2 Experiences and anticipated problems
With a large amount of RES generation being promoted by the policy, the DSOs are faced with a large
number of new connection requests from RES facilities. Large and unevenly distributed generation
facilities require huge network investments. However new investment for the network may be
stranded if there is a change or cancellation of the plan of those distributed generations. The current
method of network planning evaluates only the worst case in a sense that the peak demand is8realized, but this could be inappropriate because the technical constraints may be violated also inother times. In addition, it is difficult to process such a large number of the requests for connection.
All of these factors make the network investment planning difficult for DSOs under the existing
method.

Number of HV/MV transformers

DSOs would also have to deal with a technical problem that they have not experienced previously.
Historically, the electricity used to flow from transmission to distribution network. When a lot of RES
facilities are connected to the distribution network, the electricity may flow from distribution totransmission network [Eurelectric 2013a]. This reverse power flow may cause a voltage rise. In
European countries, the reverse power flow is observed in more than 1% of 8,760 hours per year
recently. The Italian case is shown in Figure 5. The total number of transformers is about 3,300 in the
Italian distribution system. Reverse power flows from distribution to transmission network is now
caused more frequently by high penetration of RES generation. One of the solutions is to upgrade thetransformers with larger capacity. Although it incurs cost, it can be reduced by the cooperation
between TSO and DSO.

800
July 2010

700

July 2011

July 2012

600
500
400

300
200
100

0
more than 1% in year

more than 5% in year

reverse power flow happenning hour
Figure 5: High/medium voltage transformers working in reverse power flow [Cazzateo et al. 2013]
A work group of the International Council on Large Electric Systems (CIGRE WGC6-19) gathered
information on the methods and the processes of distribution network planning from several DSOs
for a technical brochure [CIGRE C6 2014]. From the survey, the following main tasks of network
planning have been identified as illustrated in Figure 6:






analysis of market information and regulation
forecast of demand and distributed generation
network analysis
identification of alternative countermeasures to technical problems
prioritization of alternatives
9Planning alternatives
Deterministic
Network calculations

CostevaluationnoAcceptable
planning
solution?

Anyconstraint
violation?

no

yes

Network
reinforcement

yes

end

Figure 6: General planning framework for passive networks [CIGRE C6 2014]
However, DSOs are not yet fully prepared for demand response, connection of electric vehicles andadvanced metering infrastructure. In a typical network planning process DSOs depend heavily on
demand forecasts. For example, network analysis is extensively based on future demand scenarios
from the forecast. Methodologies for demand forecasts include historical trending. It is difficult toforecast the future demand from emerging technologies like distributed generation or demand
response based on historical data. Nonetheless DSOs have to manage the situation before historical
data that reflects the changing environment is available. The solutions currently considered areshown in Table 3.
Challenge

Current solution

Voltage risePower factor 0.95 lagging
Voltage/ Var control
Network capacity
Reinforcement of network equipment
Network power factor
Limits / bands for demand and generation
Sources of reactive power
Capacitor
Network asset loss of life
Strict connection design
Table 3: Present solutions for integration of distributed generation10 [CIGRE C6 2014]
They are regarded as reactive rather than proactive, with which the traditional investment planningis called fit a d forget . No D“Os seek to establish proactive distribution network planning by
utilizing demand response and batteries to control voltage/Var in order to reduce cost.
High penetration of RES generation creates not only the problem of demand forecasting but also the
problem of power quality and reliability of the network. Power quality is an important indicator for10

An increase of distributed generation could lead to an increase of short circuit current. This impact is notincluded in Table 3, perhaps because at the moment, the amount of distributed generation connected to the
network is not large enough to make it a critical issue.

10the electricity sector. There are several indices for power quality in distribution networks, forexample11

System Average Interruption Duration Index: SAIDI (respectively ASIDI, Average System … ,System Average Interruption Frequency Index: SAIFI and
voltage deviation.

In Germany the regulator publishes data on continuous unplanned interruptions of more than 3minutes12. Low voltage in Germany refers to the voltage level between 400 V and 6 kV while medium
voltage indicates the voltage between 6 kV and 36 kV. The SAIDI applied at low voltage available inGermany is a weighted average by the number of customers. The ASIDI applied at medium voltage isa weighted average by the rated apparent power of transformer.
Power quality in Germany is considered comparatively high, with an overall average of SAIDI of 15.32
minutes per year in 2013. At low voltage the indicator is as low as 2.47 minutes and at medium
voltage 12.85 minutes as shown in Figure 7. The lower SAIDI at lower network levels may reflect thehigher requirement of customers at this level or may stem from the fact that cables, which are morereliable than overhead lines, are often deployed at low voltage levels.

medium voltage

low voltage

total

Figure 7: Development of SAIDI and ASIDI in minutes/year in Germany [BNetzA 2015]
These indices indicate that reliability is not necessarily deteriorated with integration RES generation.
Historically DSOs maintain the adequacy of power systems with a certain buffer. TSOs and DSOs
make investment planning and operate the system to maintain reliability indices within a certain
range while considering cost-effectiveness. In their operation, TSOs and DSOs make good use ofexisting network equipment to decrease energy not supplied under technical constraints. Whensystem security of the power system cannot be maintained even through the maximum utilization of
the existing facilities, TSOs and DSOs consider power system enhancement to secure a stable supplyof electricity. Investment planning and operation helps each other in order to improve SAIDI or ASIDI.
It seems that for German DSOs the SAIDI plays a significant role in distribution grid planning. The
incentives for maintaining a high level of power quality for the DSOs stem from the concession
contract with the cities as well as from federal regulation. In the concessions contract, the DSO iscommitted to maintain power quality. If power quality drops significantly the DSO faces the risk oflosing the concession in the subsequent negotiations (and thus losing the foundation for the entire
11
12Frequency deviation is also used. However, frequency fluctuation is handled by the TSO.
As defined in EN50160

11

business model). However, concessions are only negotiated every 10 years. Some DSOs think that themonetary incentive from the regulation cannot drive additional investments to increase power
quality, as the quality aspect in the regulation is negligible, while other DSOs claim significant returns
from the quality element in regulation.
The greatest technical challenge of integrating RES generation takes place at low voltage level. Most
transformers in the grid today are not remotely adjustable and the scope to react to fluctuating
generation is therefore limited. In the worst case, excess generation could cause damage totransformers or customers appliances. However, this problem is usually dealt with before it arises
and the grid is upgraded as needed, maintaining better reliability with increasing shares of RES
generation. DSOs also consider countermeasure against the technical issue, like forecasting demand,
thermal limit and voltage problem.
The load profiles of smaller customers are approximated by standard profiles. In this case, the griddesign does not need an exceedingly large buffer for deviations. With increasing shares of RES
generation, it will need more excess capacity. However, large buffers are less affordable in view of
the amount of investments required. In order to decrease the investment, it becomes more
important to monitor the grid, the power flows and the asset usage in real time. The DSO prefers
cables in urban areas and overhead lines in rural areas, where much more RES generation are
expected to be installed. Maintenance is easier on overhead lines but the reliability of cables ishigher. The decision is a matter of cost and the regulation prescribes under which conditions the
additional cost13 for cables is justified. For the DSOs this is often also a political issue as cables are
more accepted than overhead lines.
Regarding the reverse power flow problems in transformers, expanding the transformer capacity is atypical counter-measure. For the voltage problems in rural areas, counter-measures are: Building
parallel lines, next to the existing lines, installing smart transformers. Curtailment of RES generation
would also be an effective countermeasure.

3.3 Recent modifications
With high penetration of RES facilities, European DSOs have to manage a more uncertain situation.
DSOs consider several modifications concerning distribution network planning in view of the changed
situation in the power system [CIRED C6 2012]. These are shown in Table 3. In addition, the objectivefunction including reliability factors has been introduced recently in the evaluation [Paulinder 2013],
otherwise DSO revenue is linked to the reliability index [Eurelectric 2013b].

13Cables can be 2.5 times more expensive than overhead lines.

12

number of countries

20
15
10

5
0
duration of
Number ofinterruptions
interruptions
indicator inindicator in
regulatory formula regulatory formula
EN50160 not binding or advisable

EN50160

Power quality
indicators

other

SAIFI

SAIDI

Figure 8: Performance on supply and power quality in regulation [Eurelectric 2013b]

80
70
60
50
40
30
20
10
0

-1100
-1000
-900
-800
-700
-600
-500
-400
-300
-200
-100
0
100
200
300
400
500
600
700
800
900
1000

Number of operators

There are more than 800 DSOs in Germany. In order to increase management efficiency, the revenue
cap as incentive regulation has been introduced into network regulation in Germany. It is difficult toimprove the reliability with only incentive regulation. Therefore a quality element has been
introduced in 2012 [BNetzA 2014]. That is, allowed revenue of the distribution network increases as
quality of supply improves [Pechan 2014]. However the impact of the quality element depends on
the bonus or penalty. A high bonus may cause overinvestment and a high penalty may lead tounderinvestment. The distribution of the actual bonus or penalty for German operators is shown in
Figure 9.

bonus or penalty amount[1000euro]
Figure 9: Bonus and penalty amounts for individual operators [data from BNetzA 2014]
In the coming years DSOs expect to consider new solutions in network investment planning as
displayed in Table 4.

13

Challenge

Future solution

Voltage rise

Demand side management
Voltage/ Var control
Storage
Network capacity
Non-firm access
Storage
Demand side management
Network power factor
Constant voltage mode
Sources of reactive power
Storage
SVC
control of wind turbines
Network asset loss of life
Constant voltage mode
Asset condition monitoring
Table 4: Future solutions for challenges with integrating distributed generation [CIGRE C6 2014]
Japanese DSOs also have to consider reliability in distribution network planning without a clear
reliability goal. According to the rules, the DSO should invest in order to shorten the interruption
period [TEPCO 2012]. Customer Average Interruption Duration Index (CAIDI) and Customer Average
Interruption Frequency Index (CAIFI) of Japanese DSOs have been very low14 except for the fiscal year
(FY) 2010 (Figure 10). CAIFI and CAIDI in the fiscal year 2010 were high due to the damages caused by
the earthquake on March 11th 2011 as well as the subsequent rolling blackout.

1

CAIFI[number/year]

CAIFI

CAIDI

0.8

500
400

0.6

300
0.4

200

0.2

100

0

0
20042005200620072008200920102011

CAIDI[minute/year]

600

FY

Figure 10: CAIDI and CAIFI in Japan [FEPC 2012]
Unlike in Germany, network tariffs in Japan are determined under a cost-of-service regulation.
Therefore Japanese DSOs can make investment in order to maintain reliability as long as they are
prudent. The cost of Japanese DSOs may increase with high penetration of RES generation in acouple of years while keeping CAIDI or CAIFI at a low level.

14

Note that CAIDI and CAIFI used in Japan reflect planned and unplanned interruptions.

14

4 Challenges and possible solutions in network pricing
4.1 Current network pricing scheme in Germany
In Germany network operators charge for network connection as well as for network use. Regulation
determines the total network cost for each network operator [§4-11 StromNEV] who then collects
the approved cost through network charges. As metering is liberalized, operation of metering
equipment, metering and billing is charged separately in addition to the network charge [§17(7)StromNEV].
Basically, network connection charges are shallow and cover only the immediate cost of connection
from the nearest network connectio poi t to the usto ers fa ilities [§9 NAV]. The shallow charge
applies to all consumers and to generators at medium and low voltage or of less than 100 MW [§9
NAV, §1+8 KraftNAV]. In addition to the shallow charges, network operators may collect a deep
charge from connections larger than 30 kW 15 covering up to 50% of the cost incurred for upgrading
the e isti g grid to a oodate the e o e tio s additio al feed-in or withdrawal [§11 NAV].
Both parts of the connection charge are collected only once and determined according to a standard
calculation and citing other comparable cases.
In Germany, only consumers pay for network use [§15(1) StromNEV]. Network use charges are fixedfor one year [§15(2) StromNEV] and do not reflect the distance between consumption andgeneration [§17 StromNEV]. In 2013 the network use charges were on average 1.78 ct/kWh forindustrial customers, 5.49 ct/kWh for businesses and 5.83 ct/kWh for private households. The
differences stem from the structure of the charging scheme as described below.
Regulation prescribes cost-reflective charges for customers [§16 StromNEV] depending on network
level, metering scheme and utilization hours [§17(1) StromNEV]. Customer charges consist of a load€/kWpeak) and an energy component (ct/kWh) [§17(2) StromNEV]. At low voltage level the metering
scheme for the majority of customers only registers consumed energy and not actual load. Loadmetering in intervals of 15 minutes is only required for customers with a consumption larger than
100,000 kWh per year [§ 12 StromNZV]. Smaller customers can apply for load metering, which isoften beneficial for customers with consumption larger than 80,000 kWh. All other customers areaccounted for based on type-specific standard load profiles (in Figure 11 at the bottom). Thosestandard customers pay only an energy charge (ct/kWh) [§17(6) S.1] and the network operator may
decide to additionally collect a ase harge €/ ear [§“tro NEV “. ]. Regulation requires thatthe total charge for the standard customer is similar to the charge resulting from the regular scheme(of energy and load components, as described below) using the standard load profile [§17(6)“tro NEV “. ]. Further ore ase a d e erg harge shall e i appropriate relatio [§StromNEV S.2]. Figure 11 depicts the distribution network charging scheme in Germany.

15

The charge then only applies for the part of the connection which is above 30 kW.

15

Figure 11: Network use charges in Germany (own figure based on Gottlob [2014])
Table 5 gives an example of the calculation for a simplified system of two subsequent network levels.
On the first level there is one customer plus the withdrawal of the subsequent level; at level 2 there
are two more customers.

Table 5: Example calculation of network charges for two subsequent levels with three customers
For each network level the general charge (postage stamp) is total cost for this level divided by thele el s yearly peak load [§16 StromNEV (1)] (in Table 5: row 3 / row 4 = row 9). Network level charges
are forwarded from higher to lower network levels according to the energy forwarded to the lower
level and the lo er le el s peak withdrawal [§14(1) StromNEV]. A customer-specific simultaneity
factor translates the network level charges to consumer charges [§16 StromNEV (2)]. The totalcustomer charge16 (load and energy charge) is the product of network level charge, customer peak16

Load and energy charges follow from this equation, as the simultaneity factor sums (1) a fixed component(the starting point of the function) driving the load part of the charge and (2) component that varies with theutilization hours (the inclination of the function) driving the energy part of the charge.

16

load and customer simultaneity factor (in Table 5: row 9 * row 4 * row 8 = row 10). Withdrawn
energy enters into the simultaneity factor via utilization hours (yearly consumption divided by yearlypeak load, in Table 5: row 5 / row 4 = row 6). Hence the load and energy part of the total charge aredetermined by the function as depicted below in Figure 12.
The simultaneity factor is a value between 0 and 1 illustrating the probability that a consumer
contributes significantly to the yearly peak load of the network level. A simultaneity factor of 0
corresponds to a probably low contribution and a value of 1 reflects a likely high contribution[StromNEV Appendix 4]. The network operator defines a simultaneity function for each network level
which assigns every customer a factor based on his utilization hours 17. The simultaneity function
consists of two straight lines intersecting at 2,500 utilization hours. For 0 utilization hours the
network operator can assign a simultaneity factor between 0 and 0.2 and for 8,760 utilization hours
regulation prescribes a factor of 1. The function must further ensure that the sum of all charges
matches the revenue-cap [§20(1) StromNEV]. Figure 12 depicts the simultaneity functions for theexample above.

Figure 12: Example simultaneity functions for two subsequent levels with three customers
Consumers with special characteristics are eligible for reductions on the network charges aspresented above. Consumers whose peak load does not coincide with the peak load of the network
level can receive reductions of up to 80% [§19(2) StromNEV S.1] 18. Large customers who withdraw
more than 10 GWh per year from the network and reach high utilization hours can also claim
reductions [§19(2) StromNEV S.2] reflecting the avoided network cost [§19(2) StromNEV S.4].
Regulation determines that customers with utilization hours of more than 7,000h are eligible for
reductions of up to 80%. To customers with more than 7,500h the network operator can grant
reductions of up to 85% and to customers with more than 8,000h of up to 90% [§19(2) StromNEV
S.3]. Importantly, these reductions do not follow the logic of high simultaneity for high utilization
17

Consumers with few, high capacity peaks can demand monthly charges to better reflect their network use[§19(1) StromNEV].
18
These reductions have been introduced in 2013; before those customers were completely exempted.

17hours. Instead the reasoning is high predictability and facilities based competition for the network
supply of these customers. The revenue foregone due to the reductions is cleared between network
operators and socialized among all network users in a surcharge [§19(2) StromNEV S.15].
Furthermore network operators can offer reductions for controllable consumers who allow the
network operator partial control over their devices [§14a EnWG]. The network operators presently
use rather simple ripple control for night store heaters or heat pumps.
While generators do not pay network use charges, the network operator remunerates generation at
distribution level for avoiding network charges at higher network levels [§18(1) StromNEV]19. The
idea is that electricity generated at lower levels (distributed generation), where the consumers arelocated, avoids transmission and distribution at higher network levels and thus defers the respective
charges. Network operators feeding into higher network levels also receive this remuneration foravoided network charges [§18(1) StromNEV]. The remuneration corresponds to the higher level senergy charge for the avoided energy and to the higher le el s load charge for the avoided peak
withdrawal 20 [§18(2) StromNEV]. Hence it does not necessarily reflect actual avoided network cost.

4.2 Experiences and anticipated problems
The current network charging scheme as presented in the previous chapter is not fit for increasing
shares of decentralized and fluctuating generation. With the ongoing change in the electricity systemfurther conflicts are anticipated.
The main problem stems from the fact that the charging scheme primarily serves to finance theinfrastructure but does not provide good signals to coordinate network users. New generators locate
in remote areas with weak network infrastructure, consumers increase peak loads whensimultaneously using new electric devices and so forth. As a consequence network operators facehigh network investments which could possibly be partially avoided in a more coordinated electricity
system. Additionally, the charging scheme provides some perverse incentives to avoid network use
by self-generation or prevent network users fle i ilit . The following chapters discuss these two
problems.
Smart metering brings another change factor into the German energy system. Today the majority ofcustomers energy consumption is only metered as a monthly or even yearly sum. Only customers
with high consumption (of more than 80,000 to 100,000 kWh) are metered continuously21. European
legislation requires a broader rollout of smart metering infrastructure. This means more precise andless aggregate metering on the one hand, and control equipment on the other hand. It is likely that
Germany will follow this requirement for a large number but not all customers. While the exact
rollout scheme is still under discussion, the development of smart metering will have a significant
impact on network charging.

19

This only applies if the generator does not simultaneously receive subsidies for RES generation or combined
heat and power generation.
20
Avoided energy is defined as the difference between energy drawn from the higher level and energy suppliedat the lower level and avoided peak withdrawal defines as the difference between the lo er le el s peak
withdrawal from the higher level and the peak withdrawal within the lower level.
21
Continuous metering is required for customers above 100,000 kW. Smaller customers can request
continuous metering at their own expense, which in practice is common from around 80,000 kW per year
onwards.

18

Another aspect in the debate which is not discussed further in this paper are the regional differences
between network charges within Germany. Generally the Eastern distribution networks have higher
charges. This is partially of historical origin as networks required significant reinforcement after
unification and hence depreciation is different than in the West. Furthermore, the Eastern regions
are less densely populated and less industrialized. Thus, network cost distributes over fewer
consumers. To a significant part, higher charges are also due to high shares of RES generation,
especially onshore wind, in those areas. The difference in network charges is increasingly seen as astructural disadvantage. Discussions evolve around socializing the extra cost for the integration of
RES generation in a nation-wide mechanism. Yet, this cost is difficult to determine. A uniform
network tariff throughout Germany is one possible alternative which on the downside foregoes theopportunity to coordinate users through network charges.
4.2.1 Coordination between network and generation or demandWith the increasing shares of RES generation in the German electricity system, generation has
evolved in remote areas with comparatively low load. In areas where the grid was historically not
built to distribute local generation this means expansion and reinforcement. The fluctuating andsomewhat uncertain nature of feed-in from wind and solar sources adds to the problem. Regulation
guarantees feed-in for RES generators at any time. The network operator can only curtail as lastresort if network stability is in danger. Network customers do not receive any incentives tovoluntarily refrain from feeding in during contingency situations. Thus rare peaks of solar generation
can cause significant investments. Network expansion may not always be the most efficient solution
to these challenges. A PV panel may only reach its nominal peak load in very few hours in summer
around noon, yet the network needs to be reinforced to distribute this peak. Wind peaks often do
not coincide with local demand and require additional transformer capacity to the transmission level.
As shown in Figure 13, studies find that curtailment of only a small percentage of this energy can cut
the necessary network investments significantly.

Figure 13: Network expansion needs with RES curtailment [translated from BMWi 2014]
Alternative siting may as well reduce the investment need and flexible demand can help to prevent
regional electricity surpluses. The activation of the demand side, however, bears potential problems.
Network operators anticipate additional electric devices. Network expansion is then needed to19accommodate additional loads. This could be the case for electric vehicles, heat pumps and small
scale storage in residential areas. Considering the flexibility of these and other consumers is a vital
part of balancing the system in the future. Yet, their synchronization due to aggregation or market
signals may increase peak loads beyond the simultaneity considered today. Again it seems that
improved coordination of this network use could economize on network expansion. Furthermore,hargi g ased o earl peak load, as it is i pla e toda , partiall pre e ts o su ers fle i ilit .
The incentive is to keep overall peak load as low as possible while increased consumption at times of
local surplus would increase peak load.
4.2.2 Self-supply
Small decentralized generators are often directly linked to a consumer. This is the case for example
for on-roof PV plants. Small-scale storage can increase their share of energy used on-site. Today inGermany, of the some 600 TWh total supply, 2.8 TWh are self-supplied from decentralized
photovoltaics and another 44 TWh self-supplied in industry. Fro the et ork operator s
perspective this generation is netted with the on-site consumption. As a consequence withdrawal
from the network reduces significantly. The consumer may even rely on the network only for backup
in case of maintenance or contingencies. Thus, the grid capacity to be kept available for thesecustomers by the network operator remains the same22. In the German kWh-based charging systemthese customers contribute less to the overall network cost than regular customers. As aconsequence, the overall network charges increase and in a vicious circle the incentive to economize
network use grows further23. Besides the perverse incentive to refrain from using the network, selfo su ers highly unpredictable, non-standard load profiles cause additional problems for network
operation.

4.3 Discussion on modifications in Germany
Network charges can set signals for location and operation of consumers as well as generators24. The
shortcomings of the present German charging scheme have led to a discussion on modifications of
network charges.
The network operators discretion to modify network charges in response to the challenges
presented above is small. The total amount to be charged at each network level and the roughcharging scheme consisting of load and energy charge according to the simultaneity factor is fixed byregulation. Hence network operators cannot increase profits by modifying charges25. Although thecalculation method for connection charges is highly standardized, network operators can influence
the simultaneity factors of certain customer groups by setting the simultaneity function. This only
concerns the starting point of the function (which can vary between 0 and 0.2) and the intersection
point of the two straight lines that constitute the function. (The intersection has to be at 2500
22

The network capacity needed by a self-consumer may even increase in case the energy produced is fed backinto the grid in times when it is not consumed on-site.
23
Self-consumers are also exempted from a number of surcharges usually collected together with network
charges (i.e. renewable energy surcharge, concessions surcharge, etc.) making the incentive even stronger.
24
Signals from network charges may get diluted on their way to the network user. They compete with possibly
conflicting signals from the market or from taxes and surcharges. Additionally in Germany, retailers forward the
network charges to consumers and may decide to average out some differentiation to avoid transaction cost.
25
Network operators will use their influence to keep charges stable and to avoid customer complaints. The
influence of local politics on network operators is often high despite the fact that they may be privatecompanies. This is due to the need to renegotiate concessions contracts every 10 or 20 years and due torepresentation of government officials in the boards of network operators.

20

utilization hours, and is thus fixed at one axis but can be freely set on the other.). Furthermore, basecharges for sta dard usto ers a e i reased up to a appropriate relatio et ee ase a denergy charge. The level of reductions is negotiated between customer and network operators.
The modifications of the charging scheme, that the challenges presented above require, need to be
implemented in the regulation and cannot be brought about only by network operators. The debate
in Germany revolves around fixed and differentiated charges as well as contributions from thegeneration side. The arguments will be presented in the following subsections. The discussion also
includes modifications of abolition of remunerations for distributed generation and reductions forindustrial customers as well as leveling network charges throughout Germany. These last aspects,
however, will not be dealt with in this paper.
4.3.1 Capacity charging
One possible modification in the current charging scheme is a shift to capacity-based charging26.
Currently, a base charge, i.e. monthly fixed charge, exists for standard customers. These customers
are not charged for occurred load but instead pay a fixed charge. Metered customers face a charge
component based on load, i.e. used capacity. The further discussion in Germany includes a fixedcharge component for connected capacity or even entirely flat charges. It can be observed that many
network operators have introduced and increased base charges in the recent years. Many also
advocate a further increase within the thresholds accepted by the regulator. This is seen as a trend
towards capacity charges.
The introduction of a capacity-based charge or a sufficiently high base charge adjusts thecontribution from self-supplying customers. It ensures a certain contribution to network cost from all
customers connected for whom the network operator keeps network capacity available. As
connected capacity is one of the major drivers for network capacity such a charging scheme can also
set incentives for network users to economize on connected capacity and thus avoid network
expansion. An entirely capacity-based, fixed charging scheme would also reduce complexity, andhence transaction cost, for networks users as well as network operators significantly. In addition, theincreased connected capacity, from new devices, such as electric cars or decentralized storage,
would be reflected in the network charges.
On the downside, a capacity charge or an increased base charge foregoes the incentives for energy
efficiency which come with energy-based charging. Environmental groups even fear incentives for an
increase in energy consumption. Also, capacity-based charges will have negative distributional effects
for those customers who consume very little and benefit those with higher than average
consumption. An entirely capacity-based charging scheme also conflicts with the remuneration foravoided network charges currently paid to decentralized generators. With entirely fixed charges
there are no charges to be avoided by these generators. In addition, simultaneity of consumption isanother important driver for network capacity and is not reflected in capacity-based charges.
Therefore in Germany a compromise with a certain part of the charge as capacity-based fixed charge
and another proportion as energy-based charge is likely. Furthermore, the incentives linked toconnected capacity may be more efficiently reflected in connection rather than use charges. Smart

26

Such a charging scheme based on available capacity - rather than occurred load is in place for German gas
networks.

21

metering may e a le load eteri g for large parts of toda s sta dard usto ers a d thus re der
the discussion about base charges obsolete27.
4.3.2 Differentiated charging
Network use charges in Germany are fixed for a year and vary between networks and network levels.
Part of the current debate revolves around a stronger differentiation according to time and locationof network use. Ideally, charges set signals for efficient siting and operation of network users.
Particularly flexible customers will shift consumption in response to these incentives. It is expectedthat the rollout of smart meters will enhance the options for differentiation significantly. Various
degrees of time and locational differentiation are possible. Higher charges during predefined highconsumption periods prevent regular peaks for example during noon or in the evenings when electricvehicles return home to charge. Real-time differentiation of charges may even coordinate
simultaneous network uses. Higher charges in constrained parts of the network steer network use
where it is most relevant, for example in residential areas with self-generation and flexible devices,while leaving other areas unconcerned. Individual charges are already in place in Germany for certain
customer groups, such as industrial customers, heat pumps, storage heating or other storage. This
concept can be interesting for other types of customers and can be decoupled from direct control by
the network operator.
Opponents of differentiated charging assume that locational factors other than network charges
dominate the siting decisions of network users. The potential for flexible operation, i.e. demand
response, is thus higher than that of influencing location. However, smaller customers without
flexible devices are expected not to respond to the signals from dynamic charges at all. The
incentives should therefore be targeted mostly at businesses, industry or special device customers. In
order to keep transaction cost low, network operators generally prefer direct control of customers
over steering via price signals. The sector currently discusses authorizing network operators to curtaila s all a ou t, e.g. to % of de e tralized ge erators earl e erg output to e o o ize
network expansion [c.f. BMWi 2014b]. It remains unclear, however, to what extent an unbundled
network operator can interfere directly with consumption and generation 28. Also in the vein ofcontaining transaction cost network operators prefer to organize coordination with suppliers or
aggregators rather than single customers. The effort and additional cost of implementing dynamic
charges may only be justified for the larger and flexible customers.
4.3.3 Generation-component
Generators currently do not pay network use charges in Germany. The reasoning is that theincidence of cost is with consumers at any case since generators would forward their use. Also therule was established to enable easy access for new generators and to enhance competition in
generation. However, the problems described in 4.2 are strongly linked to decentralized generation,

27

Despite the question of whether load-based charging is preferred over capacity-based charging, there is a
debate about whether the current German regulation prevents base charges for any customer for whommetered load data is available.
28
Another uncertain aspect is the responsibility for deviations from the expected load profiles. Currently, thenetwork operator is in charge of balancing deviations from standard load customers.

22which in the current charging system hardly receives any signals from the network 29. Consequently,
there is a discussion about introducing a generation component in network charges.
With large parts of the new generation locating in remote areas and additional generation needed in
the South of Ger a , a ge eratio o po e t refle ts the ost of et ork e pa sio i ge erators
siting decisions. In cases when rare generation peaks congest local networks, a generation
component sends signals to economize on network expansion by altering generators operation
patterns. In view of the problems from self-suppliers feeding only their excess electricity into the gridwhen needed, a generation component (in combination with the adjustments mentioned in theprevious sections) provides incentives to prevent the increase of the et ork le el s peak load.
Common criticism of a generation component in network use charging involves the following
arguments. Generators in Germany have suffered from low wholesale prices in the recent past andfind themselves in strong international competition.30 Additional charges which will be passed on to
the wholesale market and eventually consumers will weaken their position. For German industrial
customers, who bear only a small share of network cost, the resulting reduction in network charges
may be modest while the increase in wholesale prices may have a substantial effect. Additionally,
most of the generators which lack coordination are RES generators. In view of influencing siting
decisions a generation component was needed only for newly built plants, which are mostly RES
generators. They receive financial and political support and thus society may not accept additionalcharges for them. Lastly, the additional effort of charging a whole new customer group is seencritically by the network operators.

4.4 Evaluation and applicability to Japan
A large amount of intermittent renewable energy connected to the distribution network, especiallysolar PV, raised concern about financing the electricity distribution network in some major countries,
including in the U.S. (especially in California). Reforming the structure of electricity distribution
network charges has been discussed in the U.S. and it may well be discussed in other countries
including Japan in the near future. Although the support scheme for renewable energy differs
between countries, these countries would face similar problems as discussed in this report withreference to Germany.
In the U.S. there has been a discussion on capacity charging for electricity distribution companies to
cut the utility death spiral of revenue shortfall due to the increasing amount of distributed solar PV,
encouraged by net metering scheme. Historically, the electric utilities collect all of the revenue
from small customers through volume-based charges. These utilities try to have or increase the fixedcharges to offset declining sales caused by the solar PVs. Besides skepticism that the utility deathspiral is exaggerated, there have been criticisms from various stakeholders to the reliance on fixedcharges: Fixed charges to lower volumetric charges discourage energy efficiency, and adversely
impact on small customers using very small amount of electricity. Therefore the discussion has beenquite similar to that of Germany as described in 4.3.1. It is expected to be similar in other countries
as well.

29

The remuneration for avoided network charges can be considered a network signal. However, this signal
suffers from the standardized procedure of calculating the avoided charges as well as from the general
shortcomings of the current charging system.
30
The European regulator ACER is currently active to harmonize generation components within Europe.

23

To the extent that the cost structure of electricity distribution network is characterized as natural
monopoly, two-part tariff structure may well be justified as second best. It is also necessary tocompromise to some extent to avoid distributional impacts associated with fixed charges. Thesearguments are, however, based on the assumption that those who connected to the distribution
network are users of electricity from the network. Consumers with solar PV and connected to the
distribution network are able to sell their electricity generated by PV and also buy electricity from the
network as needed. These consumers actually have the right to buy and sell electricity thanks tobeing connected to the network under uncertainty of their net demand. From the financial
economics perspectives, these customers are holding such options and should be paying forpremium of these options. This would perhaps give some background for generation-component
issue. Perhaps exact pricing would be complex and less practical, but this would be another notion tothink about when we discuss the fixed charges for distribution networks. 31
Regarding a more differentiated charging, such as time-of-use tariff, there have been skepticisms
about the effectiveness when implemented among the small (i.e. household) customers not only inGermany but also in the U.S. and Japan. Various field experiments suggest that even small customers
react to price signals and change their behavior 32, although the cost-effectiveness of smart meters
would still be ambiguous as economic impact of demand response alone may not be sufficient tocover the cost of smart metering. However, Japan, for example, has already decided to roll out smart
meters to all the customers including households, in principle, by early in the 2020s and Germany
envisages a partial rollout within a similar time frame. This would open up opportunities to moreawareness of the time-varying nature of cost and new technology that enables the consumers toadjust the consumption profile without incurring much transaction cost.
Finally, we would like to point out that coordination between the network and RES generation may
well be necessary to reduce the uneconomic burden on the network operators, as discussed in 4.2.1
with reference to Germany. The curtailment of generation from RES is the main countermeasuretaken currently in Japan to solve the problem of excess energy supply from RES as described in 2.2.
Some issues remain even with the revised curtailment. The first issue is how to ensure fairness in
implementing the curtailment. Some arrangements may be necessary in case the curtailment is
implemented too often for a particular RES generator. The second issue is how to mitigate risks
associated with the curtailment. If the possibility of curtailment is perceived as economic risk forinvestors in RES projects, then it would discourage investment in RES generation. The experience ofJapan for the next several years with the revised curtailment will demonstrate the effects of forced
curtailment. Differentiated network charges for generators may send more efficient signals forgenerators to take the condition of the network into account in their siting decision and partially also
in operation. As a consequence the need for forced curtailment by the network operator is reduced.

31

For a more detailed discussion on this notion, see Pati et al. (2001).
The results of various field experiments of demand responses in Japan can be found in the website Japan
Smart City Portal (http://jscp.nepc.or.jp/en/).

32

24

5 Conclusions
In response to the global climate challenge many countries are experiencing or will be faced withincreasing shares of RES in their power supply. While Germany has been a front runner for several
decades, Japan is rapidly increasing its RES generation to comparable levels. The integration of RES
generation however entails technical as well as institutional challenges for power grids. This study
relies on recent experiences of German distribution network operators. The report distinguishes two
main trends: network planning and network pricing of a distribution grid with large-scale RES.
First, large-scale integration of RES puts the distribution grids technically under severe stress.
Conventional power grids are not designed for distributed generation and may struggle toaccommodate reverse flows and uncertain generation patterns. Problems of voltage variation andasset overloading can be the consequence. Thus, changes in network planning and ultimately
additional investments are required to keep supply quality constant. Furthermore the introduction of
distributed and fluctuating generation changes the use of the network. Regarding network planningand asset management, the study draws two main conclusions:First, technical solutions to the experienced and anticipated problems from the integration of
RES generation are available and well-known.)
Second, incentives for network operators to take efficient means to maintain supply quality
with RES generation can be implemented in regulation.

Second, large-scale integration of RES puts the structure of the distribution network charges understress. Changes in tariff structures are discussed currently. Self-supplying customers only rely on the
network for residual supply or feed-in of excess production. While requiring the same or evenadditional network capacity, their financial contribution is lower under the current charging schemes.
Likewise new generators and flexible consumers may cause significant investment by locating in aremote area or operating during times when the network is already constrained. An adequate pricing
scheme should sustainably finance the infrastructure while at the same time give incentives tocoordinate the network users. Regarding network charging the study makes the following main
conclusions:First, base or capacity charges (per kW), rather than withdrawn energy (per kWh), are ameans to reflect the network capacity provided to self-supplying network users.
Second, involving network users, i.e. generators and consumers, via differentiated network
charges may be an alternative to forced curtailment. Additionally, differentiated network
charges can also coordinate demand from new and flexible consumers.
Third, exposing generators as well as consumers to network charges is the basis for them totake system cost into account with location and operation.

The network planning and network charging options discussed in this paper stem from the casestudies of Germany and Japan. Yet, they are discussed or can be related to many other countries withincreasing RES shares. Investments into network assets take time and increase network cost.
Institutional changes are an additional and partially alternative measure. The effects of changes ingrid infrastructure and institutional framework do not show immediately but over time. Hence,
consideration of the issues discussed in this report is necessary already when developing RES
generation rather than when the mentioned technical problems are already observed.
25

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