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WP5 Final Report

Alternative cross-border cost

allocation methods for sharing

benefits and costs of integrated

offshore grid infrastructures

Date: 9 March 2015

Author: Jaap Jansen, Adriaan van der Welle, Frans Nieuwenhout, Carolien Kraan,

Francesco Dalla Longa, Karina Veum

Reviewed by:

Status of document

WP5 Final report - Alternative cross-border

cost allocation methods for sharing benefits and

costs of integrated offshore grid infrastructures

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Table of Contents

1 Introduction ........................................................................................................................................................2

1.1 Background.................................................................................................................................................2

1.2 Report outline .............................................................................................................................................2

2 Identification of alternative CBCA mechanisms ................................................................................................3

2.1 Cost allocation principles ...........................................................................................................................3

3 Selection of CBCA methods for further analysis ...............................................................................................6

3.1 Selection criteria .........................................................................................................................................6

3.2 Selecting allocation approaches – pros and cons ........................................................................................6

3.3 Allocation approaches selected for the NorthSeaGrid case studies ............................................................8

4 Applying selected CBCA methods to three case studies ..................................................................................10

4.1 Introduction ..............................................................................................................................................10

4.2 The selected cross-border cost allocation methods ..................................................................................10

4.3 General framework assumptions ..............................................................................................................13

4.3.1 General framework assumptions ......................................................................................................13

4.4 Brief description of the case studies .........................................................................................................16

4.5 Results ......................................................................................................................................................17

4.5.1 Case 1: German Bight.......................................................................................................................17

4.5.2 Case 2: Benelux-UK .........................................................................................................................24

4.5.3 Case 3: UK-Norway .........................................................................................................................29

4.6 Conclusions ..............................................................................................................................................34

5 Concluding observations regarding the way forward .......................................................................................35

References ...............................................................................................................................................................37




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1 Introduction

1.1 Background The objective of the IEE NorthSeaGrid project is to develop concrete solutions for integration of offshore wind

farms and interconnections (‘so-called integrated infrastructures’) by investigating three relevant case studies

from the perspective of individual stakeholders. This report sets out to select alternative cost and benefit

allocation methods among countries and to assess these on the basis of projected outcomes for each of the

three NorthSeaGrid case studies. A novel assessment feature of the present report is that it presents an

analysis of impacts of different CBCA methods on the net benefit allocation within-country across

stakeholders as well. For the assessment a quantitative tool has been developed and applied.

Network investment volumes have to increase substantially to accommodate a fast penetration of electricity

generation from variable renewable sources and to improve the efficiency of European electricity markets and the

resulting competitiveness of European power prices, while maintaining security of supply at high levels. In this

connection, the 2020 targets and post 2020 goals the EU has adopted, are quite relevant. Increasing investment

volumes imply an increasing number of cross-border projects between Member States. However, the current

regulatory framework has a number of flaws impeding the realization of cross-border network investments in

general. This goes in particular and a fortiori for the realization of projects that combine offshore wind park

connections and new interconnections between two or more hosting countries. Important flaws relate, amongst

others, to inefficiencies in cross-border cost and benefit allocation (CBCA) due to market and regulatory failures.

Therefore, this deliverable identifies selected CBCA methods and assesses as to what extent they are properly

aligned or not with the allocation across countries they engender of overall socio-economic welfare from

implementing integrated projects. Moreover, for hosting countries the within-country allocation across

stakeholders is analysed of the country share in the global socio-economic welfare created by integrated projects

when one-for-one each of the selected CBCA methods is being applied. This is done for each of the selected three

case studies (German Bight, Benelux-UK, UK-Norway) per selected CBCA method.

1.2 Report outline Firstly, we identify alternative CBCA methods (Chapter 2). Secondly, these methods are scored against a variety

of stakeholder criteria (Chapter 3). This results in selection of some of the most attractive alternative CBCA

methods in the context of the NorthSeaGrid project. Thirdly, in Chapter 4 the selected CBCA mechanisms are

applied to the three NorthSeaGrid case studies to identify the impacts at country level and on different stakeholder

groups within the respective hosting countries. By comparing, in each case study, the impacts between different

CBCA methods, major strengths and weaknesses of each method can be identified. Finally, Chapter 5 summarizes

and concludes.




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2 Identification of alternative CBCA mechanisms

2.1 Cost allocation principles For cross-border cost allocation as a subset of cost allocation in general, two broad cost allocation principles can

be distinguished. Firstly, we have the cost causality principle, also referred to as the beneficiary pays method

which allocates the cost as much as possible to those network users (loads and generators) which benefit from the

new network infrastructure. Secondly, we have the cost socialization principle which distributes costs over all

users accounting for the fact that some benefits such as reliability are public goods and therefore costs cannot

easily be assigned to individual stakeholders. CBCA mechanisms usually deploy one of these principles.

Generally, project promoters, supervised by regulators, apply three different general approaches for network

charging. These approaches are also applicable in the context of integrated infrastructures and are summarized

below (PJM, 2010; Pérez-Arriaga, 2010; Brattle, 2012):

Network flows: Network flows caused by network users are determined (marginally or as average) and

network costs are allocated pro-rata to each user accordingly. Network costs are finally allocated to customers

as capacity-based, energy-based or fixed charges. Flow based methodologies are applied to determine the

responsibility of network users in the construction of lines. They include the average participation,

incremental cost related pricing (ICRP), and areas of influence methods;1

The average participation method assumes that power inflows into a node contribute to the outflows

from the node in proportion to the volume of the latter (Olmos & Perez-Arriaga, 2009). After flows have

been traced, the usage of each line is allocated to network users to the extent they caused flows on the

node, as a rule 50% by producers and 50% by consumers. This method is applied in New Zealand,

Central America, and Australia.

The incremental cost related pricing method calculates the marginal costs of investment in the

transmission system which would be required as a consequence of an increase in demand or generation at

each connection point or node on the transmission system, based on a study of peak conditions on the

transmission system. The marginal costs are estimated based upon DC power flow changes resulting

from a 1 MW injection to the system (National Grid, 2014). This method is applied in the UK and

Colombia.

The area of influence method allocates costs in proportion to the network use (line flows) of the

transmission expansion by the identified beneficiaries (Olmos et al. forthcoming). The method is applied

in Argentina and Chile.

Beneficiaries pay: Network costs are allocated to those users that benefit from the reinforcement.

Beneficiaries are identified either by expected changes in production costs, wholesale energy prices, energy

expenditures and revenues or Power Transfer Distribution Factors (PTDFs) which provide an indication of the

power flows resulting from commercial transactions. Alternatively, cooperative game theory can be deployed

either to delimit distributions satisfying minimal criteria of mutual acceptability or to arrive at a unique and

feasible distribution of the total gain of cooperation. In the latter case, network costs are allocated in such a

1 Besides, transmission cost allocation literature mentions marginal participation and mean participation methods, which

are however not seen as feasible alternatives and hence discarded.




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way that they allow for stable cooperation of network users. Network costs are finally allocated to customers

as capacity-based, energy-based or fixed charges. Recently, the beneficiary pays method has been put forward

both in the US (FERC, 2011) as well as in the EU (EC 2011b; ACER, 2013d).2 NSCOGI (2013) discusses

three specific beneficiaries pay methods: the proportional to benefits method, positive net benefit differential

method, and the Shapley value method based upon game theory.

The proportional to benefits method allocates network costs proportionally to stakeholders’ benefits i.e.

every actor will have the same benefits-costs ratio.

In case of the positive net benefit differential method, negatively affected stakeholders are compensated

by all actors with (substantial) positive net benefits if an integrated infrastructure is advantageous at

global level compared to individual offshore wind park connections and interconnections. Stakeholders

that obtain highest positive net benefits have to pay the highest compensation to negatively affected

stakeholders, and vice versa. As a consequence, opposite to the proportional to benefits method, benefit-

cost ratios differ for each stakeholder.

The Shapley value method is a solution concept in cooperative game theory. For a coalition of several

players, the Shapley value assigns a unique distribution of the total gain generated by this cooperation. A

specific method applied to the electricity sector in the Brazilian context is the Aumann-Shapley method

(Pérez-Arriaga, 2011). Olmos et al. (forthcoming) explain this method by stating that ‘Locational

network charges are computed for the used fraction of the grid as the cost of the network assets used by

agents according to the Aumann-Shapley theory. This theory states that each agent is responsible for the

average incremental use it makes of the network when joining a great coalition that ends up containing

all generators and loads in the system.’

Postage stamp: Network costs are allocated uniformly among network users (sometimes consumers only),

either based upon the yearly consumed or produced energy (MWh) independent of system peak and (often)

location, or the (simultaneous) contribution of network users to the system peak (MW) independent of

location and usage. NSCOGI (2013) discusses the Louderback’s and min/max contribution methods which

partially allocate cost uniformly using a postage stamp method.

The Louderback’s method defines a direct contribution to every actor and allocates residual costs of the

global project, after direct contributions have been subtracted, across all stakeholders. Residual or

common costs are shared proportionally to the difference between stand-alone costs and attributable

costs (the latter is equal to the direct contribution). The allocation of residual costs is thus performed

with a postage stamp method, while the direct contribution is based on the beneficiaries pay method.

The min/max contribution method is similar to Louderback’s method but with different allocation of

residual costs. The residual cost contribution of those responsible for connecting offshore wind parks to

the onshore grid is the average load factor of the offshore wind park times interconnector costs at

minimum, and interconnector costs times nominal power at maximum. Thus, in the case of the min/max

contribution method again the residual costs are allocated with a postage stamp method. The minimum

2 If the beneficiaries pay method is applied usually the CBCA is based upon a CBA. Since a CBA is made of a prospective

situation, the CBCA is usually an ex-ante cost allocation mechanism as opposed to ex-post mechanisms that are based

upon the actual costs and are updated regularly afterwards.




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contribution is calculated using the average production (MWh) while the maximum contribution is based

upon peak production (MW).

Last but not least, the Equal Share principle can be considered as a specific application of the Postage Stamp

approach. This principle is often applied for cross-border cost and benefit allocation of interconnector

projects. (The relevant TSO of) each hosting country contributes an equal share to project investment and

operating costs and receives an equal share of congestion rents paid by market parties to obtain certain rights

to use project transmission capacity.




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3 Selection of CBCA methods for further analysis

3.1 Selection criteria Depending on the characteristics of the particular system (size, how well meshed the network is, fraction of the

total electricity costs attributable to transmission, number and type of prospective new network users) and

preferences of policy makers, the most adequate method of allocation may vary. Therefore, we evaluate the

alternative CBCA methods with a set of the most common criteria brought forward in the literature (PJM, 2010;

Perez-Arriaga, 2010; NSCOGI, 2013).

Oft-used criteria for the evaluation of cost allocation methods include:

Cost causality / reflectivity: those who cause more/less costs should pay for more/less costs. This principle is

firmly settled in European legislation (see e.g. Directive 2009/72/EC).

Efficient economic signals for generation and load: network cost charging influences decisions of network

users, both in the short-term (for operation decisions) and in the long-term (for investment & location

decisions). Efficiency reflects the extent to which these signals induce private decisions that promote system

efficiency.

Understandability: transparency of the tariff structure for stakeholders, so that they understand how costs are

allocated and how their decisions affect the network costs.

Administrative ease: implementation efforts, such as gathering and using the necessary data for cost

allocation.

Ability to reflect system changes over time; the utilization of network infrastructure changes over time due to

investments and changes in operation of generation and demand as well as changing market circumstances.

This criterion reflects the possibilities for updates of network charges.

Stability of tariffs; predictability of future network costs is important for investment decisions of network

users.

Recognition of the public good and positive externality aspects of transmission infrastructure; the

transmission system has characteristics of a public good. Grid reliability is a public good, as it is non-rivalrous

and (partially) non-excludable. Furthermore, the transmission system expansion can create positive and

negative externalities; benefits or costs respectively that accrue to other parties but are not taken into account

in cost allocation. This criterion reflects the extent to which the public good and externality aspects can be

included in the particular cost allocation method.

Non-discrimination; similar network utilization by different network actors should lead to similar network

charges. Opinions differ on what constitutes discrimination. Differentiation of network charges to time-of-use

or location is generally not considered as discrimination, while differentiation to (generation) technology is

seen as discriminatory. This criterion is not included in Table 1 below as it depends on the definition of non-

discrimination whether there is an impact, if any, on the scores of cost allocation methodologies.

3.2 Selecting allocation approaches – pros and cons Given the criteria enumerated in the previous section, Table 1 provides our own expert judgment of the different

cost allocation approaches in the context of integrated infrastructures analysed in the NorthSeaGrid project.

Together with the weights given to each criterion, an overall score for each cost allocation approach has been




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determined. The scoring and weighting of each criterion for each cost allocation method was put for consultation

and feedback by stakeholders (i.a. Stakeholder Advisory Board of the NorthSeaGrid project and NSCOGI).

Table 1: Expert judgment of three cost allocation approaches in the context of NorthSeaGrid

Criterion Network flows Beneficiaries pay Postage stamp

Cost causality 0/+ ++ --

Efficient economic signals for generation and

load

0/+ ++ --

Understandability - +/- ++

Administrative ease -- - +

Ability to reflect system changes over time + + +

Stability of tariffs + + +

Recognition of the public good and positive

externality aspects of transmission infrastructure

- - +

Legend: ++ very positive, + positive, 0 neutral, - negative, -- very negative.

Source: own expert judgment based upon literature survey.

The network flow approaches score moderate compared to other cost allocation approaches. First of all, some

leading researchers say there is no indisputable procedure to measure ‘physical network utilization’, all evaluation

methods are questionable, and the economic rationale for network usage methods is weak (Pérez-Arriaga, 2010).

Therefore, these approaches score moderate on the criteria ‘cost causality’ and ‘efficient economic signals for

generation and load’. On the other hand, in meshed AC networks flow approaches are considered as the only

appropriate way to determine costs and benefits. PJM (2010) also states that ‘the international trend is toward the

use of location-based or flow-based methods to allocate and recover at least some portion of transmission costs’.

In market pricing arrangements, such as flow-based market coupling in Europe and locational marginal pricing

(LMP) in several states of the US, DC load flow analysis is applied to divide scarce network capacity as

efficiently as possible. As such, cost causality and economic signals to load and generation of network flow

approaches can be assessed positively. The same holds for stability of tariffs. Often ex-ante (i.e. prospective) cost

allocation is applied with cost allocation remaining unchanged during the lifetime of the network upgrade. If

instead cost allocation is updated after installation of the network upgrade, network tariffs are less stable.

Concerning understandability, the network flow approaches require network studies which are complex and

difficult to understand for stakeholders. Moreover, earlier work packages of the NorthSeaGrid project do not

provide the required network model data for applying these type of approaches, lowering administrative ease.

Besides, network flow approaches usually measure the marginal impact on flows, which leaves aside public good

and externality aspects. As a consequence, for many aspects these approaches are considered to be inferior

compared to other cost allocation approaches.

The beneficiaries pay cost allocation approach is preferred to the other approaches on the criteria cost causality

and efficient economic signals for generation and load (both on the short and long term). The game theory variant

also takes into account strategic behavior of stakeholders. Apart from this variant, beneficiaries pay methods often

score better on understandability for the general public than methods based upon network flows. These methods,

especially those based upon game theory, are both more difficult to understand and require more data than postage

stamp approaches, lowering administrative ease. Concerning stability of tariffs, if costs are allocated to identified




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expected beneficiaries (i.e. prospectively), network tariffs are considered to be stable. If instead cost allocation

would be updated after installation of the network upgrade because of changes in beneficiaries, stability of

network tariffs would be lower. Finally, if all costs are allocated by the beneficiaries pay approach, positive

external effects such as reliability are not taken into account and not allocated to all network users but to a

selected set of actors that experience advantageous monetary impacts. Overall, a tendency exists towards

application of the beneficiaries pay cost allocation approach, both in the US and the EU. See for instance the

CBCA method developed by ACER (2013d) (see also Annex I).

The postage stamp cost allocation approach is preferred on several aspects, amongst others it is simple to

understand and easy to administrate. A well-known example of this approach is the often applied Equal Share

principle (‘50/50 division’) of interconnection costs between EU member states. Furthermore, allocating costs

over consumption and/or generation (either in energy or capacity terms) implicitly recognises that a public good

such as reliability is enjoyed by all network users. Besides, if production and consumption are stable, tariffs will

be stable as well. On the other hand, when network reinforcements are performed for economic rather than

reliability reasons postage stamp methods are increasingly inefficient. Given the increasing fluctuations in both

generation (due to increasing share of RES-E) and demand (electric vehicles, heat pumps), power flows are

increasingly variable as well, implying that the average situation is often not representative of the huge diversity

of network situations in practise. As a result postage stamp methods are increasingly unreflective of costs and

provide inefficient economic signals to network users both in the short and long term, decreasing overall system

efficiency.

3.3 Allocation approaches selected for the NorthSeaGrid case studies The postage stamp approach is often preferred because of its understandability, administrative ease, and

recognition of the public good and positive externality aspects of transmission infrastructure. Given the increasing

complexity of electricity systems (higher shares of distributed generation and less predictable RES-E, higher

network controllability due to technologic developments, and more interactions between national power systems

due to European wide market integration), simple cost allocation approaches such as postage stamp are

increasingly in conflict with the cost causality principle and provide inefficient signals to network users. It is

likely that this will provoke growing opposition from negatively affected customer groups.

More advanced are beneficiaries pay and network flow approaches. They score better on cost causality and

efficient economic signals for generation and load, but this comes at the price of both a lower understandability

and administrative ease than postage stamp methods. The beneficiaries pay approaches score better than network

flow methods: amongst others, on aspects such as understandability and administrative ease. Concerning the

latter, given that within NorthSeaGrid no detailed network model is being used, we reckoned that insufficient data

would be available for applying network flow methods. Consequently, we propose to leave the network flow

methods aside. Therefore, we propose to consider two alternative cost allocation methodologies for further

elaboration:

1. The beneficiaries pay method, notably the positive net benefit differential method which allows for

compensation payments between positively and negatively affected stakeholders. This method is

recommended and elaborated upon by ACER (i.a.: ACER, 2013d; ACER, 2013e);




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2. A combination of the beneficiaries pay and postage stamp methods. A combination of different cost

allocation methods allows for utilization of the advantages of separate methods. First, it allows for allocation

of the part of the costs that can be clearly and indisputable assigned to beneficiaries, while remaining costs are

recovered by postage stamp so that uncertainty around part of the cost and benefit items can be better taken

into account. Furthermore, application of the postage stamp method to part of the costs allows for recognition

of the public good and positive externality aspects of transmission infrastructure. One possibility is the

Louderback method (NSCOGI, 2013) which defines a direct contribution to every actor and allocates residual

costs of the global project, after direct contributions have been subtracted, uniformly across all stakeholders.




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4 Applying selected CBCA methods to three case studies

4.1 Introduction The NorthSeaGrid project analyses three case studies, i.e. German Bight, UK-Benelux and UK-Norway

(DeDecker et al. 2013) from different angles. In this chapter, results from numerical analyses of cost and benefit

allocation are presented, applying successively distinct cross-border cost allocation (CBCA) methods.

In contrast with other studies, amongst others NSCOGI (2014), this report not only presents analyses of distinct

cross-border cost allocation (CBCA) methods on their net benefit impact at country level but analyses intra-

country impacts on stakeholders as well. This is done in two steps. First, an analysis is made of the cost allocation

between countries. Subsequently, for each of the hosting countries per CBCA method the within-country

allocation among stakeholders of the country net benefit differential (net benefit of the Integrated Project minus

net benefit of the Base Case) is analysed. As for the second step, we adhere to the subsidiarity principle which

stipulates that actions should be performed at the lowest possible governance level. The information on the

resulting within-country net benefit allocation may provide additional relevant information for governments to

position themselves in inter-country negotiations, regarding the choice of the CBCA method to be applied. It may

also inform the with-in country debate on possible measures to rebalance the outcomes across stakeholders, such

as a revision of network tariffs or, subject to NRA approval, the final allocation of project congestion income.

The analysis presented here, performed in NorthSeaGrid WP5, builds on the previous NorthSeaGrid WPs. WP4

has delivered: (i) the definition of the Base Case for cost-benefit analysis, (ii) infrastructure cost data from DNV

GL, and (iii) certain input information from the ICON model on differentials of the Integrated Case and the Base

Case (gross) benefits excluding infrastructure cost. All cost and benefit data was expressed in net benefit

differentials, expressed in million euros of year 2014. Note that the derived data used by WP5 from the social

economic welfare perspective concerning benefits may deviate to some extent from information presented in the

WP4 report.

The chapter is structured as follows. First the selected allocation methods are explained in more detail (Section

4.2). Next the general framework assumptions underlying the numerical analyses are presented (Section 4.3). This

sets the stage for the core of this chapter, the numerical cost and benefit allocation analyses for each of the three

case studies (Section 4.5), preceded by a succinct description of the case studies (Section 4.4). The chapter winds

up with concluding remarks in 4.5.

4.2 The selected cross-border cost allocation methods ACER3 and NSCOGI are pivotal institutions, investigating the cross-border cost allocation issue. ACER focuses

on the more generic case of power and gas interconnectors against the backdrop of overseeing the progress

towards reaching the so-called Target Model (for the electricity and gas market respectively). According to ACER

(2013d), cross-border cost allocation can best be arranged on the basis the Beneficiaries Pay principle. To be

more specific, ACER favours the application of CBCA methods that yield at least a non-negative (incremental)

3 The Agency for the Cooperation of (EU) Energy Regulators, headquartered in Llubjana, Slovenia.




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net benefit for each hosting country in projects of common interests (PCIs), when needed through compensation

payments from countries that significantly benefit from the PCI concerned.

NSCOGI has made an extensive review of a range of CBCA methods for application to a hybrid asset serving

renewable generation and cross-border trade (NSCOGI, 2013 and 2014a). A key necessary pre-condition before

proceeding to cross-border cost allocation, is that the global net benefit of the hybrid asset case is positive.

NSCOGI made a valuable assessment of the respective strengths and weaknesses of each allocation method

considered without selecting a preferred one.

Three principle cross-border allocation methods were retained for detailed application to integrated offshore grid

infrastructures, based on a review of various allocation methods previously made by (van der Welle, 2013). i.e.:

The Conventional method

The Louderback method

The Positive Net Benefit Differential (PNBD) method. Two variants, PNBDvar1 and PNBDvar2 have

been investigated.

These CBCA methods can be described as follows:

1. Conventional: The conventional method stands for CBCA practices prevailing to date. It assumes:

An allocation for financing an interconnector on a 50/50 basis by the national TSOs of the two

hosting countries (and a 1/3 : 1/3 :1/3 basis for three hosting countries, etc.) 4

The same (Equal Share) allocation rule for interconnector congestion rents among the national TSOs

Cost allocation within countries is based on national regulations regarding, notably, support schemes,

responsibility for connecting offshore wind farms, internal congestion rents, market integration and

network tariffs.

2. Louderback: Allocate to the entity concerned its directly attributable costs (direct costs) and its part in the

total non-directly attributable costs (common costs) proportionally to one variable, i.e. its share in the

difference between stand-alone cost minus direct costs. The allocation of the direct costs can be regarded

as an application of the Beneficiaries Pay principle, whilst the Louderback allocation of the common

costs can be regarded as an application of the Postage Stamp principle.

3. Positive Net Benefit Differential (PNBD): Establish the Net Present Value of differential costs and

benefits of the Integrated Infrastructure investment proposal compared to the Base Case. To ensure

consistency with Work Package 4 of the NorthSeaGrid project, the Base Case defined in Work Package 4

has been retained, i.e. a situation including the stand-alone investments. The net benefit of the Integrated

Case results from discounting annual differential cash flows of benefits minus costs of the Integrated Case

minus the corresponding Base Case cash flows for each distinct entity (country, within-country

stakeholder). Contingent on the compensation rule to be agreed upon, allocation of the total investment

4 Alternatively, a division based on the cost of the infrastructure on the territory of each of the hosting countries might be

chosen by the national regulatory authorities concerned.




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and operating costs of the Integrated Case will be broadly in line with the respective net benefits (NPVs)

of the affected countries. The crux is which pre-set compensation rules to apply.

The first compensation variant applied by NorthSeaGrid follows ACER (2013) stipulating that hosting

and third countries with a ‘significant’ positive net benefit (default 10% of the sum of positive net

benefits) provide compensation to hosting countries5 with a negative net benefit proportionate to their

share in the sum of positive net benefits above the threshold. This variant should at best be ‘minimum

Pareto-optimal’, i.e. ending up with some countries ‘winning’ and leaving the other countries having pre-

compensation a negative net benefit, at most with a neutral net benefit position.

To reduce lingering negotiations between Member States, the second compensation variant negates the

net benefit impacts on third countries altogether, recognizing that this may imply free-riding issues

when significant negative or positive net welfare effects upon third countries are induced by

implementation of the Integrated Case. But under the given level of European integration it would appear

to be hardly politically feasible to realize compensation transfers between integrated infrastructures

hosting countries and third countries. Moreover, the second compensation variant pays tribute to the

political reality that in a joint project there should be ‘something in it’ for every hosting country.

This variant will assume that hosting countries for which a net benefit ‘return’ below a pre-set positive

value (default threshold: 10% of the sum of positive net benefits) will be compensated up to this threshold

as a maximum. The compensation will be up to a lower level than the threshold value across-the-board for

all compensation-eligible countries to the extent that the sum of surplus positive net benefits exceeding

the threshold fall short of providing compensation up to the threshold. Hosting countries with a

‘significant’ positive net benefit contribute compensation proportionate to their share in the sum of

positive net benefits above the threshold. Hence, under this variant the less well-off hosting countries in

terms of induced welfare effect are compensated beyond minimum Pareto optimality in principle:

contingent on available surplus positive net benefit, the compensation transfers to ‘the losers’ will more

than offset the negative net benefit in a project situation without compensation. In practice, when the sum

of positive net benefits of hosting countries above the threshold falls short of ensuring a significant

positive net benefit for all hosting countries, the national regulatory authorities will be inclined to agree to

request European funding (the Connecting Europe Facility) to bridge this financing shortfall. Eventually,

ACER may have to make final interventions to prevent the resources of the Connecting Europe Facility

from pre-mature depletion.

As it appears easier to implement a more rigorous but also more complex compensation transfers between

stakeholders within one jurisdiction, it is proposed that stakeholders with a positive net benefit will be imposed to

provide compensation funding with an upper limit equal to this positive amount until all stakeholders with

negative benefit value are fully compensated for this negative amount. Hence for all four variants, the within

5 The restriction of compensation-receiving countries to hosting countries only may not be fully in line with the spirit of

Regulation (EU) No 347/2013 (EU, 2013): see e.g. Annex V, principle (10) of this Regulation. Presumably ACER has

opted so for practical reasons, i.e. to reduce the complexity of negotiations that have to lead to a final investment decision.




13

country compensation is assumed to be minimum Pareto-optimal (some stakeholders gaining and other

stakeholders being compensated up to just reaching a neutral net benefit position).6

In a second step, the net benefit impact for stakeholders within countries is determined. The information on

intra-country distributive impacts of a certain CBCA method, agreed upon between hosting countries, may inform

the political debate in the countries concerned on the intra-country distributive impacts. Therefore this

information is relevant for the national regulatory agencies concerned in helping to define their respective

negotiation positions towards achieving a final investment decision on the integrated project concerned. In turn,

these impacts might be one of the drivers prompting one or more of the country governments concerned to

consider redistributive measures (e.g. through adjustment in network tariffs). Evidently, analysis of such measures

goes beyond the scope of the NorthSeaGrid project.

4.3 General framework assumptions 4.3.1 General framework assumptions Scenario studies indicate that offshore wind has a prominent role to play in contributing to the EU’s medium and

long term electricity supply. This holds notably if EU and, where applicable, Member-States self-determined

longer-term renewable energy targets are to be achieved in the most cost effective way.7 A crucial facilitating

factor for the take-off of offshore wind is the realization of offshore grid infrastructures. However, upon take-off

of offshore wind in the Northern Seas, dedicated near-shore locations that can command sufficient public

acceptance will become in short supply. For other available locations typically integrated grid solutions have the

potential to become most cost-effective. Therefore, upon the availability of advanced transmission technology,

foreseen early in the 2020s, offshore grid infrastructure will increasingly have to encompass ‘hybrid components’,

i.e. components combining the transmission of electricity traded cross-border and the evacuation of electricity

from offshore wind farms. This poses huge regulatory challenges. For instance, in an integrated grid

infrastructure, the power from connected offshore wind farms can flow to several hosting countries. This raises

questions such as which zone does an offshore wind farm operator have to bid into? Which support scheme is

applicable and which country (countries) has (have) to pay the support benefits? These and other regulatory

challenges have to be tackled. Hence, the case of offshore wind may become a potent driver for the accelerated

transition of European electricity markets towards the aspired Internal Energy Market for electricity.

Considering the foregoing, the following general framework assumptions were applied:

For overall project consistency reasons in the analysis of distinct cross-border cost allocation methods, the

base case that was defined in chapter 4 has been retained. Therefore, we focus here on the relative differences

between the integrated case and the stand-alone case noting that the methodology developed here can also be

applied fruitfully when adopting another base case.

6 During the NSG Stakeholder Advisory Board meeting and NSG-CEPS workshop held in Brussels on 13 and 14 January

2014 quite useful discussions took place on methods for cross-border cost allocation. The two proposed compensation

variants with regard to the PNBD method set out to allow for the outcomes of these discussions. As stated already in the

main text, in the case study examples in the next section as for the PNBD method only the first variant will be applied. 7 See for example (European Commission, 2011 [14]; Rohrig et al, 2014 [15]: p.25, Table 3)




14

Our analysis is performed mainly from a social welfare perspective as reflected by the applied assumptions

such as the social discount rate of 4%. We assume that the efficiency gain achieved in case of the integrated

case is not significantly affected by effects that are not taken into account in this analysis (e.g. network

reliability or other effects discussed in (van der Welle, 2014). All amounts of money mentioned below are at

constant prices, expressed in euros of 2014 i.e. €2014.

Network users will ultimately pay for the network cost, made by the TSOs concerned and approved by the

competent national regulatory agencies (NRAs). Generation Use of System (GUoS) charges as percentage of

total (transmission) system charges in accordance with (ENTSO-E , 2014) i.e.

Belgium 7%

Denmark 4%

Germany 0%

Great Britain/UK 27%

Netherlands 0%

Norway 38%

The Consumer Use of (Transmission) System charges are the complement of GUoS charges (both adding to

100%).

Typically, in the so-called TSO model (Meeus, 2014) congestion rents are accruing, at least initially, to the

TSOs.8 Here, it is assumed indeed that the TSOs receive the congestion rents due to them under prevailing

interconnection agreements. They will hold these inflows under a separate account. The NRAs concerned are

assumed to decide on the ultimate destination of the congestion rent inflows.

Production support benefits for OWF operators for hosting countries in the case studies with offshore wind

farms in their respective exclusive economic zones, defined as projected average support level in excess of the

average ex post commodity price (€/MWh), normalised in an approximate way over 20 years:9

Belgium 70

Denmark 60

Germany 60

Great Britain 90

Netherlands 90

Support cash flows to the operators of offshore wind farms (OWFs) located in the exclusive economic zone

(EEZ) of country A will be ultimately passed on to electricity consumers of country A as a volumetric

surcharge (i.e. as a function of their electricity consumption volume on a per MWh basis) on their energy bill.

8 As per ACER regulation on the use of congestion rents, the competent national regulatory agencies (NRAs) mandate

TSOs under their supervision to pass on a residual part of congestion rents in use of system charges, when this income

cannot be spent on, notably, approved investments in interconnectors. 9 Note that support levels contractually promised to new offshore wind projects are often revised, e.g. because of revised

regulatory framework conditions. E.g. in the Netherlands the Dutch TSO will become responsible for offshore

transmission of wind power, whilst currently wind farm operators have to make offshore grid arrangements themselves to

eject their generated energy to the Dutch shore. Furthermore, so far no OWFs have been realised in the exclusive

economic zone of Norway.




15

In case (part of) the electricity produced by an offshore wind farm in the EEZ of interconnected country A is

physically evacuated to the shore of interconnected country B, the competent authority on support payments

in country A remains responsible for support over the volume of exported electricity concerned. In other

words, country A is responsible for support over the total offshore wind energy production in its EEZ,

irrespective of to which jurisdiction the electrons concerned flow.10 The other side of the medal is that country

A enjoys the benefits of hosting offshore wind farms (employment, value added, green sunrise industry

development, etc.) and is entitled, in principle, to the target accounting benefits over the offshore wind

energy, produced in its jurisdiction.11

OWFs in the EEZ of a certain country have to bid into the applicable bidding zone of that country, even if the

anticipated commodity price in (one of) the other hosting country (countries) is higher and/or the physical

flow is into another direction than towards aforementioned zone.

In the case of hybrid assets, OWFs are assumed to have to pay for the connection to the interconnector or to

the offshore hub that is part of an integrated infrastructure concerned. Note that, to the extent that already

regulations exist on this issue in national jurisdictions, this assumption might not be fully consistent with

current national regulation. However, prior to realising integrated investments, the hosting countries

concerned need to align their respective regulations. The assumption made may enable the alignment

needed.12

In case of congestion on offshore interconnector structures OWFs have access priority for the notified power

injection capacity at the intraday gate closure time. In line with current regulations in most NSCOGI

countries, OWFs are given a waiver to pay for access to the transmission network; even in the event of

congestion.

As, to date, third countries and their constituent stakeholders are typically excluded in the attribution of the

cost of an interconnector between two countries this can give rise to significant ‘market failures’. Grid

electricity stakeholders in third countries with positive net benefits get a free ride to the detriment of their

counterparts in the countries on both ends of the interconnector. As a result, potential interconnector

investment projects that may be socio-economically beneficial from a global (EU-wide) perspective may fail

to pass the final investment decision hurdle. On the other hand, countries directly involved in an

interconnector project and their constituent grid electricity stakeholders may be free-riding on the back of

(stakeholders in) third countries facing negative aggregate net benefits. With a view to these considerations, in

the first variant of the Positive Net Benefit Differential allocation method the economic welfare impacts on

third countries have been included in compensation transfers. The countries considered in the case studies are

the ones distinguished in the ICON model, described in the previous Chapter.

10 This assumption has been made to facilitate an unambiguous allocation of the support benefits when more than two

countries are interconnected. 11 This assumption was made as this arrangement is the easiest to implement, precluding the need to validate to which

country what part of the produce of a wind farm connected to the integrated grid infrastructure concerned has been

ejected. This issue can become more complex the more hosting countries are involved. Evidently, the interconnected

countries concerned may agree otherwise ex ante as per bilateral/multilateral/regional offshore wind cooperation

agreement, i.e. on the transfer of a defined part of the target accounting units. 12 This is a general framework assumption. In order to be consistent with WP4 of the NSG project, no allowance has been

made for these costs in the case studies.




16

For assessing within-country stakeholder welfare impacts, in the case studies the following stakeholder

categories are distinguished:

Consumers

Offshore wind farm operators (WFOs)

Other producers

TSOs.

4.4 Brief description of the case studies13 The NSG project has selected three case studies for in-depth investigation:

Case 1: German Bight

Case 2: Benelux – UK

Case 3: UK – NO.

Each case study distinguishes a Base Case and an Integrated Case. In the Base Case a separate interconnector

transports trade energy and radial connections transports ‘wind energy’ from the case study offshore wind

farm(hub)s with the onshore transmission network of their respective ‘home countries’. In the Integrated Case

trade energy and wind energy are transported in combination in offshore integrated transmission structures.

Figure 1: Overview of the three case studies

Case Study 1 in a nutshell is as follows:

Base Case

German wind farm (hub) near Austerngrund connected to DE

German wind farm (hub) near Sylt cluster connected to DE

Interconnection cable between DK and NL (also compared without interconnector)

13 This section is extracted from (DeDecker, 2013).




17

Integrated Case

Wind farm near Austerngrund connected to both NL and DE

Wind farm near Sylt cluster connected to DE

Interconnector between the split hub and the hub.

Case Study 2 can be succinctly described as follows.

Base Case

BE wind farm hub (platform A and platform B, both connected to BE, and interconnected with a link between

them) ( seen as one wind farm in this section to be able to include the NL wind farm)

NL wind farm off the Borssele coast, connected to Borssele

Interconnection cable between BE and UK (also compared without interconnector).

Integrated Case

BE wind farm hub connected to Belgium and to NL

NL wind farm connected to the Belgian hub

Interconnection cable between UK and the Belgium hub.

Case Study 3’s Base Case and Integrated Case are:

Base Case

UK Dogger bank, connected separately to the UK

Interconnection cable between UK and NO (also compared without interconnector)

Integrated Case

UK Dogger Bank wind farm hubs connected to each other and to UK

Part of UK Dogger Bank connected to NO to create a ‘split’ connection.14

4.5 Results 4.5.1 Case 1: German Bight

Country level results

The results in terms of net benefit differentials, i.e. net benefit of the Integrated Case minus net benefit of the Base

Case, expressed in million euros of year 2014 purchasing power, are shown in Table 2. The amounts in bold

italics denote net benefit differentials (in M€2014), i.e. the net benefit value of the Integrated Case minus the net

benefit value of the Base Case (which is the situation including the stand-alone solution). A number of main

trends can be observed.

14 By connecting Dogger Bank to both UK and Norway, a split connection is created. Because the capacity of Dogger Bank

is very big, several large-capacity cables are needed to the UK anyway. Connecting one of them to Norway creates an

interconnector which is shorter in length and therefore cheaper. Since there is a large capacity to the UK, the availability

of the NO-Dogger cable for trade will be very high still.




18

The global (differential) net benefit of the proposed Integrated Project considered in Case Study 1 is projected to

show a high positive value, i.e. 1382 M€. Hence, when deciding in favour of the proposed integrated project

instead of the stand-alone project solution, the stated amount in net socioeconomic welfare (SEW) gain can be

generated. On aggregate, non-hosting countries are hardly affected (-3M€, applying the Conventional CBCA

method). When applying Conventional, Germany is the projected big winner (6746 M€), Denmark the big loser (-

5333 M€) and the Netherlands experiencing on balance an almost neutral SEW effect (-28 M€). In the next sub-

section the major undercurrents, leading to these projected results will be explained.

Table 2: German Bight: Summary table: breakdown of differential global net benefit among countries (million

€2014)

Country

CBCA method

DE DK NL Third Total

(Net Benefit IC minus net benefit BC) countries

Conventional

6746 -5333 -28 -3 1382

Louderback

5981 -4950 355 -3 1382

PNBDvar1

1385 0 0 -3 1382

PNBDvar1: required transfers among countries *) -5361 5333 28 0 0

PNBDvar2: required transfers among countries *) 675 355 355 -3 1382


*) A negative (positive) amount is an outgoing (incoming) transfer.

Source: ECN based on data from ICON model and DNV GL

Applying the Louderback CBCA method, the rather unbalanced distribution of global (differential) net benefit

across countries is slightly mitigated. Still the resulting (projected) aggregate net benefit outcome for Denmark (-

5333 M€) would seem to be a non-starter for Danish official project negotiators. The PNBD CBCA method seeks

to redress the projected disparate country-distributional SEW outcomes. We have applied two compensation rules

leading to Pareto optimal results. Applying the rule recommended by ACER (2013) leads to neutral overall SEW

impacts for Denmark and the Netherlands. As ‘there should be something in it’ for all hosting countries, we have

applied a second compensation variant leading to significant SEW gains for all three hosting countries. Should the

negotiators of all hosting countries have faith in the project selection and SEW projection methodology applied

and its results, this variant might be a useful starting point for negotiating a final investment decision on the

German Bight integrated project.

The German Bight case study confirms that notably, but not only, Germany has a lot to gain from the take-off of

integrated, meshed offshore transmission grid; the more so the more importance offshore wind assumes in the

overall German and European power supply portfolio. A graphical representation of the projected differential

SEW impacts of the CBCA Conventional, Louderback, PNBDvar1 and PNBDvar2 methods is shown in Error!

Reference source not found.




19

Figure 2: Case 1: German Bight - Alternative allocations over countries of net benefits (M€)

Intra-country distributive impacts

The intra-country distributive impacts in terms of net benefit (differentials) are visually summarized in the Figure

3 below. These outcomes are explained successively for each of the hosting countries in the remainder of this

Sub-section. As for impacts on third countries and associated stakeholders, brings out that these are rather small.

Figure 3: German Bight: impact of applying the Conventional Method for CBCA on

within-country total differential net benefit for stakeholders

Let us consider the underlying factors of the socio-economic welfare (SEW) result for Germany and the intra-

German distributive impacts among distinct stakeholders, when applying the Conventional cross-border cost




20

allocation method. The bottom line of Table 3, breaking down the projected SEW gains of Germany (6746M€),

shows that the big winners in Germany of an integrated grid solution instead of a stand-alone solution are the

power generators. Both (German) ‘other producers’ and offshore wind farm operators feeding into the proposed

integrated project, generate a producer surplus. This relates to an upward price effect as German offshore-wind

power is causing less congestion in Germany: in the Integrated Case part of this power is directly injected into the

Danish and Dutch onshore transmission grids. The transmission redundancy created by the integrated solution

relieves the intra-German transmission network and mitigates in Germany the so-called merit order effect from

variable wind power with a consequential reduced downward pressure on average wholesale power prices in

Germany.

Offshore wind power operators receive a triple dividend from the integrated infrastructure solution: as their

production can be injected into the grid more readily, they are facing less curtailment events. Hence, annual

production volumes are positively affected. Therefore, offshore wind power operators gain from higher volumes,

higher average prices, and higher production-related support benefits. Other producers also gain from a volume

effect in terms of higher exports, resulting from less congested German transmission networks. The gain in total

producer surplus is offset to a large extent ̶ but not completely due to higher German power exports ̶ by a loss in

German consumer surplus. German consumers lose twice: they are facing on average higher power process than

is the case of the stand-alone solution. Moreover, the higher offshore wind power production gives rise to higher

RES support charges to be paid for by German power consumers. In contrast, a positive factor for German

consumers is that under the Conventional CBCA method, the project costs of the proposed integrated project for

Germany is lower than the stand-alone project solution. As a result, transmission cost of system charges to be

borne by German power consumers are lower. On aggregate, German TSOs are hardly affected in terms of

congestion rent receipts: against high gains in congestion rent receipts from the integrated offshore transmission

infrastructure, TSOs are facing lower receipts of congestion rents from other German interconnectors. In order to

allow for full TSO cost recovery, this difference would have to be compensated by levying higher network

charges on network users.

Table 3: German Bight: Conventional method - breakdown of differential net benefit for Germany across

stakeholders (million €2014)

Benefit category

Consumers TSOs WFOs Other Total

(Benefit IC minus benefit BC) producers

Consumer surplus

-10687 0 0 0 -10687

WFO producer surplus

0 0 1506 0 1506

Other producer surplus

0 0 0 14890 14890

Congestion income, project-related infrastructure 0 2603 0 0 2603

Congestion income, other interconnectors 0 -2531 0 0 -2531

Inter-stakeholder transfers of production support -2110 0 2110 0 0

-/- Total differential cost

965 0 0 0 965

Total -11832 72 3616 14890 6746





21

If the hosting countries of the German Bight project opt for another CBCA method, this will only affect the last

benefit item: (savings on) total differential infrastructure cost. It depends on the country-specific transmission

system charging how changes in offshore transmission network costs propagate to transmission network users. In

Germany, all (approved) transmission network costs are passed on to the (‘non-privileged’, i.e. mainly retail)

power consumers; German power generators obtain power transmission services free of charge. 15

Table 4 below shows the resulting SEW effects within Germany from a different distribution of the total

differential infrastructure cost when either one of the distinct CBCA methods is to be applied.

Table 4: Germany: net social welfare effect for stakeholders of distinct CBCA methods regarding total cost and total

net benefit differentials (million €2014)

Effect on Total Cost Diff.(stakeholder

attributions) Effect on NB Diff (stakeholder attributions)

CBCA

method

Consumer

s

TSO

s WFOs Other Total

Consumer

s

TSO

s WFOs Other Total

producer

s

producer

s

Conventional 965 0 0 0 965 -11832 72 3616 14890 6746

Louderback 199 0 0 0 199 -12597 72 3616 14890 5981

PNBDvar1 -4396 0 0 0 -4396 -17193 72 3616 14890 1385

PNBDvar2 -5107 0 0 0 -5107 -17903 72 3616 14890 675

The left part of this table shows how the total cost differential for the country concerned (here: Germany)

propagates into the differentials in net benefit receipts per stakeholder category. The right part of the table show

what the total effect is on net benefit differentials for each of the distinct CBCA methods. For the Conventional

method, all the right-hand side numbers of the first row of figures of Table 4 match with those in the bottom line

of the preceding Table 3. For compiling the same table as the one above for the other CBCA methods, only the

second last row of Table 3 and the bottom line (Total) need to be replaced with the corresponding figures in Table

3. All other figures in Table 2 are the same for each CBCA method. Hence, the combination of Table 2 and 3

contain detailed information in the incidence on stakeholder categories of country level net benefit differentials

resulting from application of all CBCA methods considered here.

Having already discussed the stakeholder results when applying the Conventional method, we continue to explain

the main differences in stakeholder incidence between the two PNBD variants and the Conventional method,

regarding overall post-compensation German net benefit. As the differences between Louderback and

Conventional are rather small, we focus below on the two PNBD variants.

In the case of Germany, being a significant winner when the integrated solution will be implemented, application

of one of the PNBD variants implies that a higher share of the total project cost bill has to be paid by Germany,

after allowance for compensation transfers. This will ultimately be passed on to the German power consumers

through higher use of transmission system charges. Applying the PNBD method, German consumers face higher

15 This holds for Generator Use of Transmission System charges.




22

aggregate network charges ranging from 4396 M€ (variant 1) to 5107 M€ (variant 2). In contrast, applying

Conventional and implementing the integrated solution instead of the stand-alone solution would give German

consumers an aggregate advantage in terms of reduced network charges of 965 M€. Applying the Louderback

method yields results only marginally different from those of Conventional.

As already stated, Denmark as a whole is projected to lose a substantial amount of SEW (-5333 M€: see Table 1

above) from an integrated solution when the Conventional CBCA method is to be applied. Danish generators are

the most important losing stakeholder category: increased volumes of German offshore wind power directly

feeding into the Danish onshore transmission network in combination with an already quite high share of wind

power in the Danish electricity supply portfolio makes for a sharply increased merit-order effect, pushing Danish

wholesale power prices down on average. Moreover, they have to sustain a downward volume effect because of

increased competition from German wind power. This induces that the loss in producer surplus cannot be fully

offset by a gain in Danish consumer surplus. Nonetheless, Danish consumers are well off when the integrated

solution is chosen. A minus point for them (and to a minor extent for Danish generators as well) is the higher use

of transmission system charges as under the Conventional method Denmark has to pay a higher part of the bill for

project cost. As according to ICON model results, the integrated project reduces congestion within the Danish

transmission system compared to the Base Case, the Danish TSOs are projected to cash in less congestion rent

income from Danish interconnectors.

Table 5: German Bight: Conventional method - breakdown of differential net benefit for Denmark across


Benefit category



Consumer surplus

2220 0 0 0 2220


0 0 0 0 0


0 0 0 -5274 -5274

Congestion income, project-related infrastructure 0 -42 0 0 -42


Inter-stakeholder transfers of production support 0 0 0 0 0


-338 0 0 -14 -352

Total 1882 -1927 0 -5288 -5333


Table 5 summarizes the net SEW attribution to the stakeholders under all four CBCA methods considered.

Compared to the Conventional method, especially Danish consumers and to some extent Danish generators are

better off when Denmark would receive compensations by either one of the two variants of the PNBD method.

This goes to a minor extent as well when the Louderback method is applied.




23

Table 6: Case 1, Denmark: net social welfare effect for stakeholders of distinct CBCA methods regarding total cost

and total net benefit differentials (million €2014)



CBCA

method

Consume

rs

TSO

s

WFO

s Other Total

Consume

rs TSOs

WFO

s Other Total

producer

s

producer

s

Convention

al -338 0 0 -14 -352 1882 -1927 0 -5288 -5333

Louderback 29 0 0 1 31 2250 -1927 0 -5273 -4950

PNBDvar1 4782 0 0 199 4981 7002 -1927 0 -5075 0

PNBDvar2 5123 0 0 213 5336 7343 -1927 0 -5061 355

The overall SEW result for the Netherlands of a choice pro Integrated Project is almost break-even (-28 M€, see

Table 7. Dutch generators loose out from on average lower prices and lower production volumes as a result from

more competition posed by German offshore-wind power (-3423 M€). This is incompletely offset by a gain in

Dutch consumer surplus (2589 M€), because Dutch power consumers are enjoying on average lower power

prices. A less dominant countervailing effect for Dutch consumers is that they have to pay higher use of

transmission system charges as the Netherlands has to spend more on offshore grid costs when the integrated

project is chosen. German wind power will cause more congestion in the Dutch transmission system should the

integrated project be realized. This pushes up congestion rent income to be cashed in by the Dutch TSO from

other interconnectors.

Table 7: German Bight: Conventional method - breakdown of differential net benefit for The Netherlands across

stakeholders

Benefit category



Consumer surplus

2589 0 0 0 2589


0 0 0 0 0


0 0 0 -3423 -3423


Congestion income, other interconnectors 0 1199 0 0 1199



-352 0 0 0 -352

Total 2237 1157 0 -3423 -28


Error! Reference source not found. summarizes the net SEW attribution on stakeholders under all four CBCA

methods considered. Compared to the Conventional method, Dutch consumers are better off when the




24

Netherlands would receive compensations by either one of the two variants of the PNBD method. Unlike their

Danish counterparts, Dutch generators would not gain. This relates to the fact that in the Netherlands generators

are fully exempted from use of transmission system charges. Again, applying Louderback would yield similar in

nature but much smaller deviations from results obtained with the Conventional method than applying PNBD.

Table 8: Case 1, Netherlands: net social welfare effect for stakeholders of distinct CBCA methods regarding total cost




CBCA

method Consumers TSOs WFOs Other Total Consumers TSOs WFOs Other Total

producers producers

Conventional -352 0 0 0 -352 2237 1157 0 -3423 -28

Louderback 31 0 0 0 31 2620 1157 0 -3423 355

PNBDvar2 -324 0 0 0 -324 2265 1157 0 -3423 0

PNBDvar4 31 0 0 0 31 2620 1157 0 -3423 355

4.5.2 Case 2: Benelux-UK


The UK-Benelux case is an interesting one in the sense that the projected global benefit is positive (528 M€) but

other countries (read: overwhelmingly France) is gaining on aggregate more SEW than the global net benefit.

This can be gauged from Table 9 below.

Figure 4 provides a graphical representation of key results of global net value allocation across countries when

applying different CBCA methods.

On aggregate the hosting countries of the proposed UK-Benelux integrated project are poised to lose welfare.

Hence, although our projections suggest that the UK-Benelux integrated project should be implemented from a

global (i.e. European) perspective, it will not be materialized unless ‘third countries’, i.e. France, and/or additional

EU funding (e.g. through the Connecting Europe Facility) is forthcoming in order to bridge the financing gap

inhibiting a final investment decision. If funding to the extent needed by third countries, i.e. France, were to be

realised indeed, this would set nothing less than a landmark in European economic integration history. Hence,

funding by the Connecting Europe Facility would seem crucial.

Applying the Conventional CBCA method, Belgium is the big winner among the hosting countries (net benefit

differential: 2695 M€) whilst the Netherlands (-2478 M€) and to a lesser extent the UK (-708 M€) are big losing

hosting countries. As stated already, the positive net benefit of Belgium alone offers an insufficient basis for

compensating the losing hosting countries up to acceptable levels for realising a final investment decision (FID).

The project can only be realized when France is willing to substantially contribute and additional EU funding will

be made available to bridge any remaining funding gap. Even if France will accept the outcome of the ACER

recommended compensation rule (variant 1 of the PNBD method) still some 214 M€ of additional external

funding would be needed to bridge the gap towards a neutral overall SEW position for the Netherlands and the

UK.




25

Table 9: UK-Benelux: Summary table: breakdown of differential global net benefit among countries (million €2014)

Country

CBCA method

BE NL UK Third Total


Conventional

2695 -2478 -708 1019 528

Louderback

2298 -2415 -374 1019 528

PNBDvar1

371 -107 -107 371 528

PNBDvar2: required transfers among countries *) -2324 2370 601 -647 0

PNBDvar2

371 -431 -431 1019 528




Figure 4: Case 2: Benelux-UK Alternative net benefit allocations over countries (M€)


A broad summary graphical overview of intra-country distributive impacts in terms of net benefit (differentials) is

in Figure 5 below. These outcomes are explained successively for each of the hosting countries in the remainder

of this Sub-section. As for impacts on third countries and associated stakeholders,




26

brings out that these are significant. In other countries, predominantly France, on average wholesale prices are

affected in upward direction, which increases producer surplus and pushes down consume surplus. Notably the

congestion income for third countries goes up when the integrated solution is opted for. This may relate to less

available capacity for Benelux-UK trade energy exchanges, raising trade exchanges between France and the UK.

In turn, this may raise on average congestion events between France-UK interconnections and more export of

cheap French power to the UK.




27

Figure 5: Benelux-UK: impact of applying the Conventional Method for CBCA on total-within country

on total differential net benefit for stakeholders

In this Sub-section, the underlying factors contributing to the aggregate net value differential is explained for each

of the three hosting countries.

In Sub-section 0 it was stated already, that Belgium is the big winner of the proposed integrated Benelux-UK

project. Projected main winners are Belgium consumers and the Belgium TSO (See the bottom line of Table 10)

whilst the Belgium offshore wind farm operators to be connected by the Integrated Project and even more so other

Belgium generators would lose. It is in order to state that the ICON model projects lower average prices fetched

by offshore wind farm producers connected to integrated network infrastructures than by other Belgium

generators because of at times lower wholesale prices at nodes in other hosting countries. Moreover, there is a

tiny negative volume effect because of slightly more curtailment of Belgium offshore-wind power when the

Integrated Project will be implemented. The loss in total producer surplus is partially offset by a gain in Belgian

consumer surplus as Belgium is projected to be a net power importer. The Belgium TSO is projected to fetch a

sizable increase in congestion income, both on the proposed integrated project network as other interconnectors.

A main cause is pressure on the Belgium interconnectors exercised by absorption of power ejected from the Dutch

Borssele offshore wind farm, which is projected to propagate to other Belgium interconnectors.

Table 10: UK-Benelux: Conventional method - breakdown of differential net benefit for Belgium across stakeholders

(million €2014)

Stakeholders

Benefit category


producers

Consumer surplus

7077

7077


-2275

-2275


-6976 -6976

Congestion income, project-related infrastructure

651

651

Congestion income, other interconnectors

4016

4016

Inter-stakeholder transfers of production support 0.01

-0.01

0


187 1 13 201

Total 7264 4667 -2274 -6963 2695


Table 11 summarizes the net SEW attributions to stakeholders under all four CBCA methods considered.

Compared to the Conventional method, especially Belgium consumers and to a moderate extent Belgium

generators are worse off when Belgium would have to contribute compensations as specified by either one of the

two variants of the PNBD method. A change from Conventional to Louderback makes very little difference in this

particular case.

Table 11: Case 2, Belgium: net social welfare effect for stakeholders of distinct CBCA methods regarding total cost





28

Effect on Total Cost Diff.(stakeholder attributions) Effect on NB Diff (stakeholder attributions)

CBCA method Consumers TSOs WFOs Other Total Consumers TSOs WFOs Other Total

producers producers

Conventional 187 0 1 13 201 7264 4667 -2274 -6963 2695

Louderback -182 0 -1 -13 -196 6895 4667 -2276 -6988 2298

PNBDvar1 -1974 0 -13 -135 -2123 5103 4667 -2288 -7111 371

PNBDvar2 -1974 0 -13 -135 -2123 5103 4667 -2288 -7111 371

Injection of Dutch offshore-wind power into the Belgium and UK transmission grids when opting for the

integrated Benelux-UK solution will relieve the Dutch transmission grid and, on average, lead to firming of Dutch

wholesale power prices. This translates into a gain in producer surplus (5953 M€ for other producers and 317 M€

for WFO: see Table 12) and a loss in consumer surplus. The Dutch offshore wind farm to be connected to the

proposed integrated project has more options to find market outlets for its production and, consequently, is facing

less production potential forgone by curtailment events. This is poised to raise its annual production and its

receipts of production subsidies. The latter has to be paid by Dutch consumers. Moreover, Dutch consumers are

projected to have to pay higher transmission system user charges because of a higher Dutch contribution to

offshore grid infrastructure cost. The Dutch TSO is poised to experience a notable change in congestion rent

inflows. Gains in congestion rents fetched through its share in congestion rents from the integrated project

infrastructure are more than offset by far by lost congestion rents on other Dutch interconnectors.

Table 12: UK-Benelux: Conventional method - breakdown of differential net benefit for the Netherlands across


Stakeholders

Benefit category


producers

Consumer surplus

-5102

-5102


317

317


5953 5953


1970

1970


-5449

-5449

Inter-stakeholder transfers of production support -62.51

62.51

0

-/- Total differential cost -167 -167

Total -5331 -3479 379 5953 -2478


Table 13 summarizes the net SEW effect on stakeholders under all four CBCA methods considered. Compared to

the Conventional method, Dutch consumers are better off when the Netherlands would receive compensations by

either one of the two variants of the PNBD method. Again in this case the outcomes under the Louderback

method deviate rather little from those when Conventional is to be applied.

Table 13: Case 2, Netherlands: net social welfare effect for stakeholders of distinct CBCA methods regarding total

cost and total net benefit differentials (million €2014)




29


CBCA


producers producers

Conventional -167 0 0 0 -167 -5331 -3479 379 5953 -2478

Louderback -105 0 0 0 -105 -5269 -3479 379 5953 -2415

PNBDvar1 2203 0 0 0 2203 -2961 -3479 379 5953 -107

PNBDvar2 1879 0 0 0 1879 -3285 -3479 379 5953 -431

Table 14 below shows that inflows of Belgium and Dutch offshore-wind power puts downward pressure on UK

power prices. As a result UK power consumers will gain in consumer surplus (3694 M€). This is projected to be

offset by loss in producer surplus by UK generators (-3540 M€). The UK TSOs cash in more congestion rent on

the integrated project infrastructure (OFTOs) but this is more than offset by loss in congestion income from other

interconnectors. Under the Conventional CBCA, the UK has to pay higher offshore grid costs (-382 M€) which is

passed on under the prevailing UK grid charging practices to UK consumers (73%) and generators (27%).

Table 14: UK-Benelux: Conventional method - breakdown of differential net benefit for the UK across stakeholders

(million €2014)

Stakeholders

Benefit category


producers

Consumer surplus

3694

3694


0

0


-3540 -3540


702

702


-1183

-1183

Inter-stakeholder transfers of production support

0

-/- Total differential cost -279 -103 -382

Total 3416 -481 0 -3643 -708


Table 15 summarizes the net SEW attribution to stakeholders under all four CBCA methods considered.

Compared to the Conventional method, both British consumers and generators are better off when the UK would

receive compensations by either one of the two variants of the PNBD method. Applying Louderback instead of

Conventional gives limited improvement to British consumers and generators.

Table 15: Case 2, UK: net social welfare effect for stakeholders of distinct CBCA methods regarding total cost and

total net benefit differentials (million €2014)


CBCA


producers producers

Conventional -279 0 0 -103 -382 3416 -481 0 -3643 -708




30

Louderback -35 0 0 -13 -48 3660 -481 0 -3553 -374

PNBDvar1 160 0 0 59 219 3854 -481 0 -3481 -107

PNBDvar2 -77 0 0 -28 -105 3618 -481 0 -3568 -431

4.5.3 Case 3: UK-Norway


Country level results of CBCA analysis of the UK-Norway case study are shown in Table 16 below. The

following trends are projected to emerge from a choice of the Integrated Project instead of the postulated Base

Case stand-alone solution:

A significant global net benefit differential is projected (696 M€) with only minor SEW impact on ‘Other

countries’(18 M€). Hence the Integrated Project would qualify to be implemented from a European SEW

perspective.

Under the Conventional CBCA method the UK is projected to be the big winner (5146 M€) and Norway

the big loser (-4468 M€), with application of Louderback only marginally mitigating this unbalanced

situation.

Should the negotiators wishing to reach a FID accept the applied base case, CBCA assessment

methodology and results of this report, a FID can only be reached by major compensation concessions

granted by the UK to Norway. The PNBD method provides a useful basis to that effect.

Variant 2 of the PNBD method provides the lowest compensation amount by the UK. It assumes, perhaps

less realistically so, that Norway will contend itself with a projected net benefit differential outcome of

zero.

PNBD variant 2 assumes that the UK will agree to the highest compensation amount of all CBCA

considered in this report, i.e. 4648M€. This leaves the UK with a net benefit differential of 498 M€,

whilst Norway would also gain to the tune of 180 M€. Note that the UK has insufficient surplus net

benefit to allow Norway to reach a positive net benefit at the threshold level corresponding with the

compensation rule of variant 2. The projected threshold level in the UK-Norway case amounts to 516 M€.

Table 16: UK-Norway: Summary table: breakdown of differential global net benefit among countries (million €2014)

Country

CBCA method

UK NO Third Total


Conventional

5146 -4468 18

696

Louderback

2948 -2270 18

696

PNBDvar1

678 0 18

696

PNBDvar1: required transfers among countries *) -4468 4468 0

0

PNBDvar2

498 180 18

696

PNBDvar2: required transfers among countries *) -4648 4648 0

0






31

The net benefit distributions across countries under four selected CBCAs are graphically depicted in Figure 6

below.

Figure 6: Case 3: UK-Norway Alternative net benefit allocations over countries (M€)





32

A broad summary graphical overview of intra-country distributive impacts in terms of net benefit (differentials) is

in Figure 7 below. These outcomes are explained successively for each of the hosting countries in the remainder

of this Sub-section. As for impacts on third countries and associated stakeholders, Error! Reference source not

found. brings out that these are rather small.

Figure 7: Benelux-UK: impact of applying the Conventional Method for CBCA on

within-country total differential net benefit for stakeholders

Table 17 below shows details of the intra-UK distribution of the UK net benefit differential to the tune of 5146

M€ among UK stakeholders, assuming the Conventional CBCA method is being applied. The Integrated solution

would tremendously benefit the operators of offshore wind farms to be connected to the proposed UK-Norway

Integrated Project. First of all they would collect a huge producer surplus, fetching at times higher prices on the

Norwegian power market and experiencing less production loss through curtailment events. The latter factor also

brings in much higher production subsidy income. Other UK generators are also benefitting from evacuation of

UK offshore-wind power to the Norwegian market, raising average wholesale power prices on the UK power

market. UK consumers bear the brunt of most of the gains by UK offshore wind farm operators. First, they have

to eventually pay a much higher offshore-wind power support bill. To make things worse for the UK power

consumers, they have to face higher power prices (i.e. a loss in consumer surplus of 7512 M€). The onshore UK

TSO is poised to lose congestion income, following a relaxation in pressure on the UK network by UK offshore-

wind power. Implementation of the Integrated Project under a Conventional method CBCA agreement is

projected to reduce the offshore network infrastructure cost for the UK by 2525 M€. Given the prevailing UK

transmission network charging practices, this cost saving is shared by consumers (1843 M€), WFOs (23 M€) and

Other generators (659 M€).




33

Table 17: UK-Norway: Conventional method - breakdown of differential net benefit for the UK across stakeholders (million €2014)

Stakeholders

Benefit category


producers

Consumer surplus

-7512 0 0 0 -7512


0 0 9450 0 9450


0 0 0 1262 1262



Inter-stakeholder transfers of production support -8653 0 8653 0 0


1843 0 23 659 2525

Total -14323 -579 18127 1921 5146


Table 18 summarizes the net SEW attribution to stakeholders under all four CBCA methods considered.

Compared to the Conventional method, both British consumers and generators are worse off when the UK would

have to contribute compensations as specified by either one of the two variants of the PNBD method. Applying

Louderback yields results about halfway between Conventional and PNBD.

Table 18: Case 3, UK: net social welfare effect for stakeholders of distinct CBCA methods regarding total cost and

total net benefit differentials (million €2014)



producers producers

Conventional 1843 0 23 659 2525 -14323 -579 18127 1921 5146

Louderback 238 0 3 85 327 -15927 -579 18107 1347 2948

PNBDvar1 -1419 0 -18 -507 -1943 -17584 -579 18086 755 678

PNBDvar2 -1550 0 -19 -554 -2123 -17715 -579 18085 708 498

Under the Conventional CBCA method, Norway is poised to lose out 4468 M€ of aggregate net benefit

differential, when the Integrated Project will be implemented. Table 19 below provides some details how this loss

is projected to be distributed among Norwegian stakeholders. In the absence of Norwegian offshore wind farms,

all Norwegian stakeholders are projected to lose:

Consumers, because of loss in consumer surplus and because of higher transmission system charges

because of the additional offshore grid bill for Norway. The consumer surplus effect derives from more

export of cheap Norwegian hydro power to the UK, giving some upward pressure on Norwegian power

prices. This is partially offset by price pressure exercised by UK offshore wind power.




34

Norwegian power generators are facing more competition from cheap UK offshore wind power. This

generates on balance more loss of Norwegian production surplus, than the gain associated with export of

hydro power to the UK.

The integrated project modestly reduces the strain on the Norwegian interconnections with consequential loss in

congestion rent income for the Norwegian TSO.

Table 19: UK-Norway: Conventional method - breakdown of differential net benefit for Norway across stakeholders

(million €2014)

Stakeholders

Benefit category


producers

Consumer surplus

-1238 0 0 0 -1238


0 0 0

0


0 0 0 -915 -915





-1333 0 0 -817 -2150

Total -2571 -165 0 -1732 -4468


Table 20 summarizes the net SEW attributions to stakeholders under all four CBCA methods considered.

Compared to the Conventional method, both UK consumers and generators are much better off if Norway would

receive compensations determined by either one of the two variants of the PNBD method. Again results under

Louderback are in between those under Conventional as against under either one of the two PNBD variants.

Table 20: Case 3, Norway: net social welfare effect for stakeholders of distinct CBCA methods regarding total cost and total

net benefit differentials (million €2014)



producers producers

Conventional -1333 0 0 -817 -2150 -2571 -165 0 -1732 -4468

Louderback 30 0 0 18 48 -1208 -165 0 -897 -2270

PNBDvar1 1437 0 0 881 2318 199 -165 0 -34 0

PNBDvar2 1549 0 0 949 2498 310 -165 0 34 180




35

4.6 Conclusions

The three case studies indicate that the Conventional method yields rather unbalanced allocation of the global

(differential) net benefit among affected countries. Louderback tends to only slightly mitigate these unbalanced

outcomes. Proper cost compenstation transfers would seem necessary to arrive at an investment proposition on an

integrated project that is acceptable to at least all hosting countries. Two alternative compensation rules have been

applied to adjust the cross-border cost allocation under Conventional, i.e. PNBDvar1 and PNBDvar2.

Among the three case studies, third countries are scarcely affected in therms of welfare impacts in the cases

German Bight and UK-Norway. Yet in the Benelux-UK case, third countries benefit significantly. Only in the last

case a major EU funding contribution would seem necessary to render the case potentially acceptable to all

hosting countries.

The incidence of (differential) net benefit among stakeholders within the hosting countries concerned tends to be

rather uneven. It would seem appropriate to pay explicit attention to within-country stakeholder impacts in the

project preparatory period towards the final investment decision.




36

5 Concluding observations regarding the way forward For meeting cost-effectively 2030 EU climate and energy headline targets and even more so for 2050 EU carbon

reduction targets, offshore wind has a substantive role to play. For making this happen, the best sites will soon be

taken and gradually less shallow sites further away from shore sites have to be used. Hence, for implementing the

EU climate and energy policy agenda in the most cost-effective way, the implementation of a properly planned,

meshed offshore grid consisting of integrated infrastructures needs to take off early in the next decade. One of the

key pre-conditions to be fulfilled is the EU-wide adoption of socio-economically sound and well-balanced cross-

border cost allocation. The results of applying a distinct CBCA method should be robust in nature for different

generation scenarios.

Based on criteria analysis this report has identified three main CBCA methods for further investigation, i.e.

Conventional, Louderback and Positive Net benefit Differential (PNBD). For the latter method two variants were

introduced. Next, for each of the NorthSeaGrid case studies numerical analysis was performed of (differential)

cost and benefit allocations resulting from these methods at country level and, as a novel feature, within each of

the hosting countries at stakeholder level.

The results of numerical analysis at country level suggest that the Louderback method and, often even more so,

the Conventional method give rise to less balanced to sometimes highly unbalanced outcomes, as regards the

distribution of net socioeconomic benefits among countries and across stakeholders. Therefore, these two methods

are considered less suited for providing ‘benchmark guidance’ to negotiations on cross-border cost allocation of

integrated offshore infrastructure projects.

Our main recommendation is to apply a net benefit method that yields a non-negative or rather a significant

positive incremental net benefit for each hosting country of an integrated offshore infrastructure project as pivotal

point of departure for negotiations between the national regulatory agencies concerned aimed to arrive at financial

closure. In this policy brief the Positive Net Benefit Differential method has been applied to that effect. This

method is consistent with the Beneficiaries Pay principle; it mitigates free riding.

Moreover, it is recommended to also assess the welfare impacts of the integrated project under consideration to

stakeholders within each of the hosting countries. The NorthSeaGrid has pioneered such an assessment for each of

the three NorthSeaGrid case studies. The analysis described in this report has brought the assessment of distinct

cross-border cost allocation methods a significant step further in that also projected intra-country distributive

impacts have been included in the analysis. This yields additional relevant information to negotiations at country

level between the respective national regulatory agencies.

In prospective applications of the PNBD method, issues meriting due further attention include the choice of Base

Case assumptions. For instance, should it be a situation including the relevant stand-alone projects or should the

cost-benefit analysis be a ‘stand-alone’ CBA16? Also the rule for compensation between countries should be

investigated further; it is to strike a delicate balance between theory and political feasibility. Besides, the

robustness of net benefit projections at country level should be tested under several plausible scenarios.

16 See ACER (2013), page 8. This refers to a cost-benefit analysis of a proposed project (e.g. an integrated offshore

infrastructure project), where the counterfactual base case is an entirely stand-alone situation, i.e. without other projects.




37

To conclude, the right regulatory framework conditions need to be in place in the hosting countries of integrated

infrastructures to level the playing field for investors in offshore wind farms. Not only their support schemes need

to be aligned, also their use of system charges and congestion management regulations facing operators of

offshore wind farms. Their electricity markets should ideally be fully aligned cross-border in all time frames,

including the cross-border intra-day and balancing markets. Next, hosting countries should closely coordinate

planning and oversight of offshore wind and grid infrastructure. Moreover, with respect to the power produced by

wind farms feeding into integrated grid structures legislation should be developed and implemented in (at least)

the hosting countries, governing the division among hosting countries of responsibility of support payments as

well as renewables target accounting benefits. Also it should be legally stipulated in which bidding zone (or

hosting country) the offshore-wind power concerned should be sold. The general framework assumptions

presented in this report provide possible directions for solutions on these scores. Properly filling the legal voids

hindering the implementation of integrated offshore infrastructures would appear to be a matter of high urgency.

As Member States are reluctant to relinquish power bestowed on them by the subsidiarity principle, bottom-up

regulatory streamlining efforts among key stakeholders of like-minded littoral states with due advisory support

would seem to be most promising approach towards kick-starting integrated offshore grid projects.




38

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