dominoes deliverable d5.3 cost benefit analysis of the...

DOMINOES – DELIVERABLE

D5.3 Cost Benefit Analysis of the Business Models

This project has received funding from the European Union's Horizon 2020 research and

innovation programme under Grant Agreement No. 771066.

Deliverable number: D5.3

Due date: 30.09.2020

Nature1: R

Dissemination Level1: PU

Work Package: 5

Lead Beneficiary: CNET

Contributing Beneficiaries: EDPD, Empower, LUT, VPS

Reviewer(s): USE

1 Nature: R = Report, P = Prototype, D = Demonstrator, O = Other

Dissemination level: PU = Public PP = Restricted to other programme participants (including the Commission Services) RE = Restricted to a group specified by the consortium (including the Commission Services) CO = Confidential, only for members of the consortium (including the Commission Services) Restraint UE = Classified with the classification level "Restraint UE" according to Commission Decision 2001/844 and amendments Confidential UE = Classified with the mention of the classification level "Confidential UE" according to Commission Decision 2001/844 and amendments Secret UE = Classified with the mention of the classification level "Secret UE" according to Commission Decision 2001/844 and amendments

D5.3_Cost Benefit Analysis of the Business Models of 92

Version Date Description

1 11.09.2020 Document revised by the contributing

beneficiaries

2 21.9.2020 Document revised by the reviewers

3 25.9.2020 Document ready for submission

Authors

Eduardo Rodrigues, Gisela Mendes, Luisa Serra – CNET

Guido Pires, José Manuel Terras – EDPD

Sirpa Repo, Riikka Hirvelä – Empower

Salla Annala, Samuli Honkapuro – LUT

Luisa Matos, Lurian Klein – VPS

Disclaimer

The views expressed in this document are the sole responsibility of the authors and do

not necessarily reflect the views or position of the European Commission or the Innova-

tion and Network Executive Agency. Neither the authors nor the DOMINOES consortium

are responsible for the use which might be made of the information contained in here.


1 Introduction 7

2 DOMINOES general objectives and context 8

2.1 General objectives ..................................................................................... 8

2.2 Social context ........................................................................................... 10

2.3 Economic context .................................................................................... 11

2.4 Political context ........................................................................................ 12

2.5 Institutional context ................................................................................. 14

3 CBA of the business models 16

3.1 Aggregation of small-scale flexible loads as a universal virtual power

plant ........................................................................................................... 19

3.2 Aggregator flexibility provision to DSO for network management..... 31

3.3 Using transactive energy for network congestion management ........ 39

3.4 Sharing the exceeding PV generation in the scope of energy

communities ............................................................................................. 45

3.5 Retailer as user of the local market ....................................................... 57

3.6 Energy service provider in enabling / assistive role for local markets

and providing ECSP capability for retailers, communities or other

service providers ..................................................................................... 79

4 Conclusions 88

References 90


Executive Summary

The DOMINOES local market platform proposes a new way of aggregating value the

transactive energy from distributed generation and the flexibility from distributed demand

response and other energy resources available at the community level. This deliverable

highlights the results from the cost-benefit analysis of the business models nourished by

consumers and prosumers willing to become active market participants and earn from

their flexibility while benefitting an entire value chain, from generation and energy service

companies, operators and retailers, to energy service providers and communities.

The project general objectives and the context framing the presented cost-benefit

analysis identified and comprehensively described. The main characteristics and

forthcoming requirements from the considered social, economic, political and institutional

environment, impacting the use cases’ validation and the business models’

implementation, are presented. The methodology adopted is also highlighted,

introducing the major guidelines, the proposed framework and the fundamental steps

followed by the cost-benefit analysis over the six business models considered within the

scope of the project.

D5.3, on the cost-benefit analysis of the DOMINOES business models, aims to define

the boundary conditions and setting all the relevant parameters impacting all the direct

and indirect possible losses and gains achieved by local market participants through their

marketplace engagement and action. For the six business models considered, focused

on the aggregation and service provision as virtual power plant, on the system operator

as beneficiary from transactive energy and flexibility available at local level to optimise

network’s operation, on the sharing of exceeding distributed renewable generation at the

community level, and on the retailer as user of the local market for portfolio optimisation

and unbalance settlement, the most relevant parameters influencing their market access

and operation are identified, quantified and valued. These parameters, which will feed

specific cost-benefit and sensitivity analysis over the different business models, are then

overviewed and their range, enabling a positive outcome for the targeted stakeholders,

are highlighted.


List of Acronyms

BM Business model

BRP Balance responsible party

CAPEX Capital expenditure

CBA Cost benefit analysis

CER Renewable energy community (from Portuguese)

CM Community manager

DER Distributed energy resources

DG Distributed generation

DR Demand response

DSO Distribution system operator

EBITDA Earnings before interests, taxes, depreciation and amortisations

ECSP Energy community service provider

EPES Electrical power and energy system

ESS Energy storage system

EU European Union

EV Electric vehicle

FSP Flexibility service provider

GHG Green-house gases

HEMS Home energy management system

HR Human resources

HV High voltage

ICT Information and communication technologies

KPI Key performance indicator

LEFM Local energy and flexibility market

LM Local market

LV Low voltage

MV Medium voltage

NPV Net present value

OPEX Operational expenditure

OPF Optimal power flow

P2P Peer-to-peer

PV Photovoltaic

RES Renewable energy sources

SG Smart grid


SM Smart meter

SO System operator

TE Transactive energy

TSO Transmission system operator

TV Technical validator

UC Use case

VPP Virtual power plant

VHV Very high voltage

WP Work package

INTRODUCTION


1 Introduction

Local energy and flexibility markets (LEFMs), engaging consumers and other market

stakeholders, leverages the inherent potential from distributed generation (DG), demand

response (DR) and other distributed energy resources (DER) at local level, and promotes

business cases, based on energy and flexibility exchange, directly benefitting the local

ecosystem of market actors.

The associated business potential may positively impact the clustered value-chain,

composed by energy services providers, operators, retailers and communities, but also

influences the entire market cascade, from the wholesale to the local marketplace.

The main business models (BMs) considered and already published – reported in D5.1

– are:

• Aggregation of small-scale flexible loads as a universal virtual power plant (VPP);

• Aggregator flexibility provision to the distribution system operator (DSO), or the

direct use of transactive energy (TE) for network management;

• Sharing exceeding photovoltaic (PV) generation within the energy communities;

• Retailer as user of the local market (LM);

• Energy providers enabling or assisting LMs and providing energy communities

service provision capability;

This deliverable, as part of task 5.3, comprises the results from the cost-benefit analysis

(CBA) of the new BMs developed to promote and enable the implementation of the local

energy market concept.

The CBA uses data from the use cases (UCs) that were already defined in the first work

package (WP) – reported in D1.3 – and considering the LM reference architecture and

the different business requirements – reported in D1.1 and D2.3 – imposed by

DOMINOES demo environments – microgrid, VPP and distribution grid –, an assessment

over the costs that participants may incur to become eligible to take action at local

marketplaces and the benefits directly withdrawn from market participation was

performed.

The first section introduces the deliverable content. In section 2, the project general

objectives and the context considered are explained. The objectives and their

relationship with the BMs are introduced. This section also includes an analysis over

social, economic, political and institutional context, surrounding the BMs validation and

therefore also impacting the CBA. Section 3 highlights the different BMs targeted by the

CBA and the main results, presented and explained according to the adopted framework,

aligned with the guidelines for conducting CBA of smart grid (SG) projects [1]. The last

section comprises the conclusions from the work accomplished within D5.3.

http://dominoesproject.eu/

DOMINOES GENERAL OBJECTIVES AND CONTEXT


2 DOMINOES general objectives and context

This section describes the general objectives and the context envisioned for the

implementation of DOMINOES, which aims to enable LEFM to leverage the aggregated

value of DG, DR and different DER assets integrated into different environments,

communally benefiting global energy demand & supply management, system’s operation

and community engagement, while targeting the main technical, social and economic

needs found at the local ecosystems.

2.1 General objectives

Due to increased number of decentralised and intermittent renewable energy as well as

the feed-in of electricity into grids by consumers, balancing demand and generation

becomes more difficult. In the next few years, the electricity generation structure must

change completely to overcome the mentioned concerns and to achieve certain targets.

For instance, European Union (EU) countries have committed to achieving at least 32%

of renewable share of the total energy consumption by 2030, according to the new target,

revised in 2018 [2].

Interventions to stabilise the grid are much more frequent and it is becoming more and

more complex for grid operators to manage loads, keep voltage stable across the

system, guarantee security of supply, and avoid plant shutdowns. Novel types of BMs

and services can facilitate the transition towards a more sustainable and efficient

electrical power and energy system (EPES).

According to European Commission [3] the share of renewables in electricity could be

as high as 50% by 2030, with an important contribution from variable sources. This sets

significant challenges to system’s management, particularly at the distribution level,

since a large part of the renewables will be integrated at the end-users’ premises.

Moreover, the proposal for a regulation of the European Parliament and of the council

on the internal market for electricity suggests that the end-users’ role within the future

EPES will be central [4].

The technical solutions to develop should encourage and enable consumers/prosumers

to take part in the energy transition and actively participate in market transactions.

As renewable energy sources (RES) bring great environmental benefits, by providing

clean ways of getting carbon-neutral energy and allowing DG and self-consumption, and

the evolution towards SG leverages the potential of digitisation, interoperability and

large-scale coordination, across centralised and dispersed generation, distribution and

transport operation, energy retail and consumption, the energy transaction will deeply

rely on optimal management of the system’s inner flexibility, to address future

requirements.



DOMINOES’s concept has the potential to allow the upgrade of the electrical system

without costly network expansions.

The project addresses the role that active consumers/prosumers and other relevant

stakeholder can play in energy and flexibility markets, namely the transitions from

automated grids to transactive grids.

The LM services framed, based on peer-to-peer (P2P) and other trading services by

design, are validated within the transparent and scalable LEFM framework DOMINOES

proposes, fostering different BMs that assess how a dynamic and collaborative

relationship can be achieved among the system’s stakeholders in the emerging future,

when microgrids, independent local energy communities, energy and flexibility

aggregation and VPPs will prevail.

DOMINOES establishes solutions to address the design and development of a LEFM

architecture, based on information and communication technologies (ICT) components

implementing profiling, forecasting, trading, settlement, clearance and control services

to support aggregation and balancing, validating locally enabled BMs impacting energy

service companies and aggregators, system operators (SOs), communities and end-

users, retailers and energy service providers.

The project provides a transparent architecture for LEFM where consumers can interact

and effectively exchange energy and flexibility with other market stakeholders, e.g., SOs,

aggregators, retailers and other consumers. The market architecture and services,

design to leverage DR, foster local energy, flexibility aggregation and support grid

management will help to achieve the high-level objectives and progress key performance

indicators (KPIs) outlined below.

Table 1 – DOMINOES high-level objectives and related KPIs.

HIGH LEVEL OBJECTIVES PROGRESS RELATED KPI

Design and develop a local market concept that empowers prosumers to

decide on the distribution of value of their energy resources, enables

easy demand response service provision, enables easy wholesale

market uptake of distributed resources, supports liberalised energy

markets and is compatible with the ongoing policy development.

REFERENCE ARCHITECTURE

DEFINED

PROOF OF CONCEPT DEVELOPED

CONCEPT VALIDATED

ROADMAP TO MARKET DEFINED

Develop and demonstrate ICT components that will enable the local

market concept, focusing on control technologies enabling transactive

management of resources, interoperable and open interfaces between

the stakeholders, monitoring and settlement functionalities provided by

smart meters, energy storage system solutions providing services to the

distribution grid and the consumer and market management tools for

connecting the local markets with the traditional/centralised energy

markets.

COMPONENT ARCHITECTURE

DEFINED

COMPONENT INTERFACES

DESIGNED

COMPONENTS DEVELOPED

COMPONENTS INTEGRATED



Develop and demonstrate balancing and demand response services that

forecast, profile, segment and aggregate dynamic energy resources for

the use of local optimisation, enable DSOs to manage grid congestions

in cooperation with the end-customers, provide means to include virtual

power plants and microgrids as active balancing assets and demonstrate

interoperability between local and wholesale markets.

SERVICE REQUIREMENTS DEFINED

SERVICE

EXECUTION/ARCHITECTURES

IDENTIFIED

SERVICES DEVELOPED

SERVICES VALIDATED IN RELEVANT

ENVIRONMENT

Design and validate local market enabled business models that enable

transactions inside local communities and allow DSOs to participate in

the market actions and thus create new means to manage increasing

amounts of renewables, create a platform for innovative demand

response schemes utilizing energy storage systems and other distributed

energy resources to convert excess electricity, reduce/avoid curtailment

and provide services to the grid, enable enhanced interconnections

between Member States, contribute to ongoing policy development in the

field of the design of the internal electricity market, of the retail market

and ongoing discussions on self-consumption and comply and

complement the current regulatory/legal framework especially from the

DSOs perspective.

BUSINESS MODELS' KEY

ATTRIBUTES DEFINED

BUSINESS ENVIRONMENT

ANALYSED

A SWOT ANALYSIS CONDUCTED

DEVELOPED BUSINESS MODELS

VALIDATED

Analyse and develop solutions for secure data handling related to local

market enabled transactions with an emphasis being on maintaining

integrity of communication information between operators in the network

and maintaining confidentiality of measurements, user’s data and system

parameters used in each operator.

REQUIREMENTS FOR SECURE DATA

HANDLING DEFINED

SECURE DATA HANDLING

PROCEDURES DESIGNED

PROCEDURES VALIDATED

PROCEDURES INTEGRATED IN THE

OVERALL CONCEPT

2.2 Social context

The multifaceted nature of the SG technologies available disseminated across the

mainstream power systems turns the analysis over the accessible costs and benefits

quite complex. Some of the technologies under implementation are in fast development,

adding some uncertainty to the overall assessment of the results coming from pilot

projects such as DOMINOES.

According to [5], an objective evaluation of the understood potential within each concept

validated is of paramount importance to value and leverage any inherent societal benefit

resulting from the technology maturation and integration at system level. The CBA offers

a systematic process to compare the advantages and disadvantages of a SG initiative

from the social perspective. Ultimately, the cost-benefit analytical tools available provide

a comprehensive evaluation whether a decision to invest in a technology improves the

global efficiency of common resources’ allocation. This directly impacts the energy and

climate goals identified at European level and at national level, targeting the increase of

renewable energy, the improvement of energy efficiency and the overall reduction of

carbon emissions.

SG technologies contribute to the above-mentioned goals, not only directly but perhaps

to large extent indirectly, which calls for the highlighted assessment through system-level

methodologies.



To draw conclusions about the outcomes is necessary to define social welfare. In [5] the

social welfare linked to the sectors that are relevant to the project is defined as the

aggregation of all the costs and benefits as a direct or indirect consequence of the project

implementation. In DOMINOES, the validation of the LEFM applied to different

environments – microgrids, energy communities, and VPPs –, expands the context for

which the social welfare must be assessed, since the different ecosystems have their

specific characteristics and the different impacts considered may be differently extended

over time. To reach a common metric, all impacts need to be discounted to present

values, and the decision criterion for the CBA is, therefore, the difference between the

discounted benefits and discounted costs. Whenever the sum of the benefits’ present

value exceeds the sum of the costs’ present value a positive outcome is expected, and

social welfare will increase when a positive net present value (NPV) is reached.

The concept proposed and explored in DOMINOES encompasses a paradigm change

to the main stakeholders involved. If for the actors engaged upstream in the chain the

impacts might be indirect or marginal due to the scale, for those directly involved in the

local marketplace and exposed to the market conditions specificities and its variability,

the outcomes from the project implementation may not be neglectable at all.

The CBA does not always provide the required decision support, since other impacts

than social benefits and costs may not be framed. The socioeconomic impacts across

the entire SG’s supply chain, related to job creation and export possibilities are some

examples. Considering this possible gap between the expectations and the CBA

methodology applied, parallel research and analysis of the specific societal goals should

complement the CBA over the project’s BMs.

2.3 Economic context

The DOMINOES project creates new BMs and thus new services for the market

participants so that their businesses can evolve, while these BMs also provide tangible

financial benefits. While new market participants have access to the local, wholesale and

ancillary services market, both at transmission system operator (TSO) and DSO level,

they can gain revenues from market participation. Sharing the local generation inside the

community increases possibilities to invest in renewable generation and replace the

purchase of the electricity with its own electricity generation and thus earn savings.

Service providers can receive income from new services.

In the DOMINOES BMs, the value of flexibility is considered in a new way, since the

purpose is to leverage and share the value found at the local level between new market

participants engaged within the LEFM ecosystem. Also, the associated risk is shared in

a new way, while the flexibility resources are distributed, and more actors are involved

in the flexibility value chain.



One target of the project is to show that active consumers can play a considerable role

in the energy markets. Because of this, BMs should share the value of flexibility to end-

customers as well. This can be done, for example, by sharing monetary compensation

for providing flexibility for the VPP. Another option can be the possibility to purchase

other energy-related services from the VPP: The most important thing is that the end-

customers feel that they benefit from participating in the energy markets. The

establishment of LMs and end-user engagement can be promoted also by economic

incentives by promoting the installation of DR control equipment, PV panels and small-

scale storage systems. Incentives could be e.g. investment support or tax reliefs.

The development of local energy markets creates an opportunity to utilizing the existing

resources in the most efficient way. It can, for example, reduce the need to make new

investments in the grid or provide ancillary services with new reserve power plants which

are based on fossil fuels.

It should be noted that the economic attractiveness of the DOMINOES LM solutions may

vary between countries and local conditions since the market structures and price

determination varies.

2.4 Political context

The DOMINOES project has been implemented during a period of several changes in

the European energy sectors. The goals of decreasing import dependency in this sector,

diversify the electricity generation sources and tackle the threat of climate change led to

a European energy policy strategy with the following objectives [6]:

• Ensure the functioning of the internal energy market and the interconnection of

energy networks;

• Ensure security of energy supply in the EU;

• Promote energy efficiency and energy saving;

• Decarbonise the economy and move towards a low-carbon economy in line with

the Paris Agreement;

• Promote the development of new and renewable forms of energy to better align

and integrate climate change goals into the new market design;

• Promote research, innovation and competitiveness.

To achieve the above-mentioned objectives, the Directive (EU) 2019/944 of the

European Parliament and of the Council of 5 June 2019 – [7] – on common rules for the

internal market for electricity has established several dispositions that will help reach the

following goals:

• Foster the use of renewable and decentralised electricity;

• Incentivize demand-side response, which includes consumer flexibility;

• Test new RES, namely storage at residential or distribution level.



All Member-States have until the end of 2020 to transpose most articles of the Directive

(EU) 2019/944 [7] to their national legislation.

The Directive already establishes a role on the consumer side, regarding flexibility.

According to the Directive, consumer flexibility is key to facilitate the integration of

decentralised renewable generation and, for that purpose, technological advances,

smart metering and digitalisation are an essential means to guarantee the customer’s

ability to provide flexibility services.

Regarding the role of DSO, they should have clear incentives to procure flexibility

services to consumers, for congestion management purposes, whenever this solution is

more efficient than other alternatives. The costs incurred by DSO should be allowed by

national regulators, as these will be part of the Distribution activity. All procedures

adopted by DSO must also be competitive and transparent, and the process shall be

supervised by the NRA, to assure that these principles are met.

Finally, the role of consumer flexibility will benefit from new advanced tools, such as

smart metering devices or consumer-level storage. Whereas the first one is essential to

allow customers to provide flexibility, the second one can raise the potential savings and

profitability of demand-response.

Regarding the specific Portuguese legal and regulatory framework, the public policy

strategy has been to increase the level of consumer flexibility and to make flexibility more

relevant in terms of grid management. On the one hand, the Portuguese regulator has

developed two pilot projects, in 2018 and 2019: one that had the goal of improving the

network access tariff structure, which leads to a more effective benefit associated to

demand-shifting, and another that involved consumption in providing ancillary services

(tertiary reserve). Although this pilot was focused on flexibility at generation markets

level, it is a clear sign towards involving customers in the sector’s management

decisions. On the other hand, the Portuguese government published a new self-

consumption regime (Decree-Law 162/2019 [8]), both individual and collective, and

which already opens the door to renewable energy communities (CER). The new self-

consumption regime only establishes network payment when collective self-consumption

uses the grids. All other situations will be exempt from regulated tariff payments. Also,

new legislation has been published in 2020, stating that collective self-consumption that

uses the public networks will be exempt from policy cost payments.

By introducing these new players – self-consumption and CER - in the sector, the public

policy-makers are making a solid effort to accelerate the transition to a sector with a

significant amount of renewable local generation. However, they will represent a big

challenge in terms of Distribution network management, as the DSO will have to plan

and operate its grid in a way that can accommodate these new generation solutions,

without compromising quality and safe-ty of supply. This will make flexibility tools even

more relevant, as they can provide quick and effective responses by consumers, when

compared to conventional investment alternatives.



1 - https://eur-lex.europa.eu/legal-content/EN/TXT/?uri=CELEX%3A32018L2001

2.5 Institutional context

The BMs defined in the DOMINOES project rely on a regulatory and legislative

framework that:

• Allows aggregated flexible resources to access ancillary service markets;

• Enables energy sharing and trading in communities;

• Encourages DSOs to use flexibility services.

These aspects are largely covered in the recast electricity directive (2019/944) [7], which

should be transposed into national frameworks by the end of 2020. Article 17 addresses

DR through aggregation and states: “Member States shall ensure that transmission

system operators and distribution system operators, when procuring ancillary services,

treat market participants engaged in the aggregation of demand response in a non-

discriminatory manner alongside producers on the basis of their technical capabilities.”

Before the renewed directive, the situation and market arrangements have varied widely

even within Europe. For example, according to ENTSO-E’s most recent survey on

ancillary services [9], provision of frequency containment reserve was in 2019 a

mandatory service for generators in many countries, and in the countries with a market-

based procurement scheme, the list of eligible resources varied. Furthermore, in addition

to the eligibility of resources, minimum bid sizes and the requirement for symmetrical

products pose challenges for utilising distributed resources.

The directive defines ‘citizen energy community’ as a legal entity that “(c) may engage in

generation, including from renewable sources, distribution, supply, consumption,

aggregation, energy storage, energy efficiency services or charging services for electric

vehicles or provide other energy services to its members or shareholders.” The rights of

such communities are addressed in Article 16(3) of the directive. Member states shall

ensure, for example, that they “are able to access all electricity markets, either directly

or through aggregation, in a non-discriminatory manner”, and “are entitled to arrange

within the citizen energy community the sharing of electricity that is produced by the

production units owned by the community.”

Communities are addressed also in the renewable energy directive 2018/2001 [2] which

uses the term ‘renewable energy community’. According to Article 22 of the renewable

energy direcive1, these communities should be entitled to “(a) produce, consume, store

and sell renewable energy, including through renewables power purchase agreements;

(b) share, within the renewable energy community, renewable energy that is produced

by the production units owned by that renewable energy community, subject to the other

requirements laid down in this Article and to maintaining the rights and obligations of the

renewable energy community members as customers; (c) access all suitable energy

markets both directly or through aggregation in a non-discriminatory manner.”

https://eur-lex.europa.eu/legal-content/EN/TXT/?uri=CELEX%3A32018L2001



In Portugal, the requirements of the renewable energy directive are (partially) addressed

in the Decree-Law 162/2019 which allows collective self-consumption (i.e. same unit of

energy production may have several self-consumers) and forming of energy

communities for the production, consumption, sharing, storage and sale of renewable

energy [8]. In September 2020, the Finnish legislation had not been updated to cover

energy communities.

Furthermore, Article 32 of the electricity directive addresses DSOs’ incentives to use

flexibility services: “1.Member States shall provide the necessary regulatory framework

to allow and provide incentives to distribution system operators to procure flexibility

services, including congestion management in their areas, in order to improve

efficiencies in the operation and development of the distribution system.” In many

countries, economic regulation favouring infrastructure investments has hindered the

use of flexibility by DSOs [10]. The requirement in the directive should alleviate the

situation but because the regulatory models are typically fixed for several years at a time,

the change is not going to be quick. For example, in Finland, the current model [11] will

be applied until the end of 2023.

In addition to the enabling regulatory framework, many of the DOMINOES BMs also rely

on services and products such as load and generation forecasts and home/building

energy management systems. Although this kind of services are already in the market,

integrating them into the management systems of the parties utilizing flexibility may be

challenging due to lack of standardized interfaces between different data systems [12].

CBA OF THE BUSINESS MODELS


3 CBA of the business models

The DOMINOES concept in a nutshell, as previously described, is proposing of a LEFM

structure supporting aggregation/DR services so that it will be possible to enable local

sharing and optimisation of RES in medium voltage (MV) and low voltage (LV) grids,

create relevant and liquid flexibility for innovative distribution management and empower

prosumers and DR service provision.

The considered UCs are related with the BMs targeted by the CBA, which follows the

guidelines from [1] and according to [13], for each BM addresses:

• An overview, identifying the case, describing its major objectives and any

additional information;

• Describes the technical background, characterising the technology – what and

how – and identifies the main benefits expected, the impacts and the most

relevant performance metrics;

• Defines the problem to be targeted by the CBA, evaluating the boundary

conditions and setting the fundamental parameters for the evaluation;

• And estimates the overall case impact, by quantifying and monetising cost

incurred and appreciable benefits and analysing the sensitivity to the different key

parameters variability.

The BM and their linked UC are presented in Table 2.

Table 2 – DOMINOES BMs and UCs.

Business Models Use cases

1 Aggregation of small-scale flexible loads as a universal virtual power plant

Local community flexibility and energy asset management for wholesale and energy system market value

2 Aggregator flexibility provision to DSO for network management

Local market flexibility and energy distributed resources for optimal grid management 3 Using transactive energy for network

congestion management

4 Sharing the exceeding PV generation in the scope of energy communities

Local community market with flexibility and energy asset management for energy community value.

5 Retailer as user of the local market Local community flexibility and energy asset management for retailer value

6 Energy service provider in enabling / assistive role for local markets and providing ECSP capability for retailers, communities or other service providers

Local energy market data hub manager and technical validator of market transactions



Methodology

The methodology adopted for the performance of the CBA over the different BMs follows

a common approach and is aligned with the general guidelines suggested for conducting

CBAs of SG projects.

The CBA framework flow followed is presented in [1], and the main steps of the adopted

process are proposed in [13]. The characterisation of each BM comprises the following

entries:

• A general overview of the BM, identifying the BMs and their context within the

project;

• A description of the objectives and all the relevant background information;

• The highlight of the technologies supporting the development and

implementation of each BM;

• The identification of the application scenarios, the expected benefits and impacts

and the major performance metrics to consider;

• The summary of the CBA accountable conditions, highlighting all the research

and assessment required to support every assumption and consideration made

when defining the boundary conditions and setting the parameters to identify,

quantify, value and monetise the costs and benefits involved in the analysis;

• The evaluation, through a sensitivity analysis, of the impact that the key

parameters defined will have on the solution, allowing to assess the key

parameters range of values enabling a positive outcome;

• The presentation of the CBA results and conclusions.

The abovementioned entries are framed in the subsections adopted to present and

explain the analysis performed. The BM identification includes the BM name and the

associated UCs, the physical elements and activities, the body responsible for the BM

implementation and the BM impact on stakeholders. The other entries considered focus

the BM objectives identification, its technical feasibility and environmental sustainability,

the financial analysis and the risk assessment over the implementation of each BM.

The risks' assessment comprises the identification of each risk and an overview of the

dependent impacts. Once the risks impacts are characterised, when applicable, possible

mitigation actions should be presented.

The CBA process comprises four main steps, addressing the definition of the boundary

conditions and of the parameters set. In this step all the requirements are identified, and

the proposed set of parameters is bounded to the limits imposed by these constraints.

When the boundary limits are clearly defined and bounded to the respective parameters,

and after considering all the relevant assumptions, the identification, quantification and

valuation of the key parameters must be performed. To conclude this step, the research



process required to quantify and value the entire set should be presented and clearly

explained.

Following the methodology, the CBA must be performed and a sensitivity analysis over

the results must be considered, to verify the solution robustness to key parameters.

The sensitivity analysis can highlight a significant impact that a certain constraint, a key

parameter or an assumption have on the solution, constraining, bounding or adding to

much uncertainty to the CBA result.

A recursive approach must then be considered, allowing different iterations of the

previous steps to be performed to enhance the solution.

After the conclusion of the sensitivity analysis, the CBA results can be assessed, and

the range of values for the key parameters that enable a positive outcome can be

identified.

The summarised flowchart of the methodology applied to the DOMINOES CBA is

presented in Figure 1.

Define boundary conditions and set parameters

Identification

Quantification

Valuation

Perform Cost-Benefit Analysis

Perform the sensitivity analysis

CBA results

Identification of the range of parameter values enabling a positive outcome

Figure 1 – CBA framework.



3.1 Aggregation of small-scale flexible loads as a universal virtual power plant

3.1.1 BM01 project identification

Project Business Models Use cases

1

Aggregation of small-scale flexible loads as a universal virtual power plant

Local community flexibility and energy asset management for wholesale and energy system market value

BM1 defines a business case where small-scale flexible loads are aggregated as a

universal VPP. This BM is described in D5.1 and the associated UC – local community

flexibility and energy asset management for wholesale and energy system market value

in D1.3.

3.1.1.1 Physical elements and activities

Based in D5.1, this BM consists of small loads and prosumers/consumers to whom the

VPP has contractual relations for the acquisition of flexibility. Consumer loads are the

primary source of flexibility. Flexible loads at the customer could be home appliances,

buildings’ heat ventilation and air conditioning, water heating systems, EVs, small

batteries, among others and small production units. Besides the appliances, remote-

metering and remote-control infrastructure to manage flexibility is needed. Besides them,

data management and communications IT infrastructure are needed. ICT systems of

VPP include interfaces to aggregated customers, retailers, communities, wholesale

markets and telecommunication systems to communicate with the resources.

Flexibility manager will need strong human resources (HR) skills for big data

management, energy management, IT, telecommunications and remote control.

Capabilities are needed operations management system to ensure coordination of

flexibility actions and balancing requests, as well as processes to manage field

maintenance. Identification, forecasting and validation of the flexibility are required as

well as market knowledge on providing the aggregated flexibility to different markets.

The main idea of this BM is to aggregate flexibility as a service. The flexibility service

provider (FSP) will provide the aggregated flexibility as a solution to grid operators and

balance responsible parties (BRPs).

3.1.1.2 The body responsible for BM project implementation

The main responsible for the BM is FSP. FSP could be e.g. an aggregator or a

community manager (CM).

In the DOMINOES-project implementation, VPS is the main responsible of this BM.



3.1.1.3 BM project impact on stakeholders

BM1 has a mainly local scope since the BM requires the participation of the small

distributed resources. Also, the BM customers could be LMs or local energy communities

and local DSO who is solving local network constraints. DSO is involved in the BM also

from the technical validation perspective.

The BM has a connection to the national (or regional) energy market as well (BRP or

TSO as a customer). The retailers’ participation and connection with the wholesale

market are described in BM5 – reported in D5.1.

Table 3 – Stakeholders identification and impact evaluation.

Stakeholder Role Action Impact (Benefit and downsides)

Prosumers,

consumers

“Provider” Providing the

flexibility

Monetary compensation for providing flexibility for the VPP.

Possibility to receive/purchase other energy related services

from the VPP

Possibility of negative influence of shifting the demand to less

favourable timeframe, loss of comfort

Community

aggregator

(energy

community)

“Provider” Flexibility

aggregation and

flexibility trading

Financial benefits for flexibility provision and compensation from

the DSO/TSO/BRP

DSO Customer Flexibility

purchase

Validation

Additional channel to purchase flexibility instead of investing on

network. Possible lower costs than network investment

DSO is informed on the market actions in their network and

aware of the potential consequences

Increases complexity and requires system development to be

able to utilize the whole potential of VPP resources

DSO operation is reliant from the customer behaviour

TSO Customer Flexibility

purchase

Additional channel to purchase flexibility instead of investing on

network or purchasing the flexibility from the traditional TSO

markets for lower cost

Increases competition and market liquidity and thus should lower

the price

Increases complexity because of smaller unit sizes



BRP Customer Flexibility

provision

Additional channel to purchase flexibility instead of traditional

marketplaces for lower cost

Externaliz

ed tasks

Field

installations,

maintenance

Income from installation and maintenance services of the

equipment

New service development

Regulator Market

registration

More competition on the energy and ancillary services market

Additional regulation work because new market and new market

participants

Retailer No active role in

the business

model

Possibly negative influence since the customer flexibility is

controlled by some external party if not considered in the

balance settlement

Main stakeholders of the BM are described in the Figure 2, which are the FSP,

DSO/TSO, and Community Aggregator – reported in D5.1.

Figure 2 – BM stakeholders and relations – reported in D5.1.

This BM foresees the establishment of a contract between the end-customer and VPP

for providing the aggregation service (C1 and C2 in Table 4 below). C1 aims to enable

end-customers to participate in the flexibility market with VPP and C2 where the VPP

pays a monthly fee for each of its flexible load to end-customer. C3 includes an

agreement between the VPP and the DSO. It is assumed that the DSO will make a

monthly payment to the VPP related to the flexibility services. C4 defines the agreement

between the VPP and the BRP. Contracts are described more in detail in D5.1. Table 4

characterises the types of contracts.



Table 4 – Contracts BM1.

C1 C2 C3 C4

Stakeholders

DSO ✓

BRP/TSO ✓

VPP ✓ ✓ ✓ ✓

Small customer ✓ ✓

Type Dynamic ✓ ✓ ✓

Static ✓

Payment Type

Daily ✓

Monthly ✓ ✓ ✓

Annual ✓

Pricing

Action Base ✓

Static ✓

Incentives

Dynamic ✓ ✓

3.1.2 BM01 objectives

The Energy Transition requires maximisation of renewable power use by means of

demand-side flexibility – however so far this hasn’t been done or proved viable in the

case of the aggregation of multiple small-scale flexible loads.

The objective of this BM is based on the creation of a central coordination agent (i.e., the

FSP) who will manage the flexibility resource pool from multiple prosumers, producers,

consumers, active demand and supply in a collective manner (as a universal VPP), to

reach a minimum threshold of aggregated flexibility to be sold to DSOs/BRPs/TSOs.

3.1.3 BM01 technical feasibility & environmental sustainability

3.1.3.1 Demand analysis

3.1.3.1.1 Current demand

Renewable generation has a significant weight in the Portuguese energy mix. Large

hydro and wind power are the main sources of renewable generation in Portugal. Also,

most of the DG (which includes all renewable generation except large hydro) is injected

in the distribution grid. Hence, renewables have a considerable impact on the distribution

network and thus the need for flexibility services at local level is considerable.

There are around 6,2 million customers in Portugal. Nearly all these customers are

residential and around 60 000 non-residential customers.

The Portuguese regulator, ERSE, published the Directive 4/2019, establishing a pilot

project for large (very high voltage – VHV – , high voltage – HV – or MV) customers, able



to provide offers of at least 1 MW in the tertiary reserve regulation market. In this way,

customers were, under this pilot, participating in a market where only large generators

used to participate. This pilot project started in April 2019 and was expected to last 1

year. However, due to the positive results of the pilot, ERSE decided to extend it. This

pilot was developed under the supervision of ERSE, and REN, the Portuguese Global

System Manager, was the responsible party for managing the customer offers. This was

also a challenge for the Portuguese DSO, EDP Distribuição, as it had to assure that

consumption fluctuations due to market offers made by customers would not impact its

grids. This new flexibility tool has the potential to face a significant demand, as all

customers able to offer at least a 1 MW load increase / reduction could qualify to join this

scheme. However, there were only around 30 interested consumers, and 6 consumers

qualified to participate in this pilot. Consumers would make bids, with prices associated

to the amounts of load they would make available, and they wouldn’t have to pay

electricity network access tariffs in the cases where they were offering to increase their

load, as they were offering a service by increasing their consumption.

Another flexibility tool that is in place in Portugal since 2010 is the Interruptibily

Mechanism, created 10 years ago. This mechanism is managed by the Portuguese TSO,

which is REN (as REN plays both the role of System Manager and TSO). Under this

Mechanism, large customers (connected at least at MV level) can offer the possibility of

having its load interrupted, under an order of the TSO. Unlike the pilot for tertiary reserve,

in this Mechanism the DSO can ask the TSO to issue load reduction orders for customers

connected to the Distribution networks, if there are technical reasons to do so. In 2019,

there were 49 consumption points participating in this scheme (there are around 24.000

MV, HV and VHV customers in Portugal), and the available load to curtail was around

720 MW.

At LV /residential level, there are currently no flexibility mechanisms in place, although

there are already some dispositions, regarding CER in the Decree-Law 162/2019. As

such, it is possible that the following years will be marked by new flexibility schemes

involving aggregation and residential customers.

3.1.3.1.2 Future demand

It is expected that, in the future, there will be more prosumers at residential level since

new legislation will allow for collective self-consumption and the creation of energy

communities. Also, the growing number of electric vehicles (EV) will bring new

challenges for the distribution network management.

3.1.3.2 Option analysis

Currently the options for the BM scenario are related to the grid operation nowadays or

providing flexibility only from the large-scale flexibility units.



In the business as usual- scenario for the grid operators and BRPs, they will use existing

means, tools, resources and their possibilities. Grid operators invest in network assets,

like increase transformer size or replace the existing lines or use bilateral contracts for

flexibility with predefined flexibility resources. BRPs use their own assets for balancing.

In this scenario, there is no need for FSPs.

As an option for aggregating small-scale resources, FSP utilizes only large-scale

flexibility units to flexibility for networks and BRPs. Whit this scenario there is less

competition in the flexibility markets and thus the flexibility prices might be higher and

there could be scarcity of flexibility in some situations. The option means that some

flexibility value is lost for the whole system.

The BM scenario is that the flexibility potential of also small customers is used by

aggregating the resources. The BM requires a scalable solution since the number of

endpoints is large. In the small-scale flexibility resources, there is big unused potential

to provide local and system services. Drivers that direct to proposed BM would be a

potential push from the regulation and legislation, a need from the customers to provide

more value from the resources and increasing request for flexibility in the energy system

locally and nationally.

3.1.3.3 Environment and climate change considerations

The BM has no physical impacts on soil, water and air, and no biological impacts on

flora, fauna and ecosystems.

In social impacts, there will be no impacts on land uses, patrimony, and people-focused

impacts such as population density, employment and hazards. There will be an impact

on local electrical grids. Local impact could mean grid losses reduction. The impact on

global electrical system can be the increase in the overall system efficiency and the

impact on households can be energy savings and new revenue streams.

For the climate change perspective, the BM has an indirect impact on climate change

because of:

• More incentives to install renewable generation → less coal-based power

generation

• More efficient use of resources and energy

• Increasing the market liquidity in provision of ancillary services and smoothing of

electricity demand curve → less use for peak power plants

These all will have an impact on green-house gases (GHG) emissions. It’s very hard to

quantify the impact.



3.1.3.4 Location and technical design

BM1 customers are in the DOMINOES-project small commercial and industrial

consumers, e.g. hotels, offices or community buildings.

Besides the physical resources (customers and their equipment) BM requires ICT-

system, human capital resources and organizational resources to meet the BM

requirements. Third-party resources might be needed for non-core activities such as field

installations and maintenance.

3.1.3.4.1 Location

The BM will be implemented in the DOMINOES project in Portugal, in the northern and

central part of the mainland.

3.1.3.4.2 Technical design

In the BM1, the customers are equipped with meters, controllers, gateways, repeaters

and sensors. Typically, the installation of the equipment at the customer premises takes

a full working day for a medium-size customer. Figure 3 describes the architecture for

each VPP site.

Regarding the technical design of the ICT-systems, the VPP consists of:

• Customer interface;

• Aggregation tool;

• VPP tools;

Figure 3 – Architecture of VPP site in BM1.



• Validation tools;

• Forecasts of production/consumption;

• Flexibility potential evaluation;

• Market interaction interfaces.

3.1.4 BM01 financial analysis

3.1.4.1 Introduction

The context of this BM1 is the BM evaluation for the VPP manager and their capabilities

to aggregate small loads and offer the aggregated energy/flexibility to other markets. The

idea of the BM is to enable electricity market participation of the small customers and

based on the electricity market revenues, share them between the VPP manager and

the customers. The small customers haven’t this opportunity now.

The BM is evaluated for VPP which would consist of around 120 homes and 80 small

offices.

3.1.4.2 Investment cost, replacement costs and residual value

The necessary initial investment consists of start-up and technical costs, equipment and

machinery.

Start-up & technical costs are related to the costs with market access, e.g. registration

to the electricity market places, accreditation needs and licensing. In the evaluation of

this BM, these are not considered since it is assumed that the VPP manager is already

a market participant.

Equipment costs consist of ICT platform and interaction platforms with different market

participants.

Machinery is needed at the customer premises to enable the flexibility resource

monitoring and control. The machinery includes:

• Remote-metering and control, appliances to small loads. Remote metering and

control to manage flexibility from small loads are both required. Small loads for

example, EVs, batteries and water heating systems. There are two options on

how to organise the ownership of the controlling equipment:

o 1st model – customer owns the equipment: The customer pays up-from

HW costs and they pay a fee per transaction. The customer receives

revenues of his sales (energy + flexibility) coming from the LEM

o 2nd model – customer doesn’t own the equipment: The customer doesn’t

pay the up-from fee and will pay a fixed monthly instalment and a fee per

kWh sold in the market

In this BM1 evaluation, the second model is evaluated.



The total initial investment is assumed to be 201.280,00 €.

Replacement costs and residual value are not considered in BM1.

3.1.4.3 Operating costs and revenues

The total operational costs are assumed to be 753.000,00 € for 15 years.

It consists of:

• Personnel costs: strong HR skills are needed for big data management, energy

management, IT, telecommunications and remote control as well for ICT platform

operation, flexibility aggregation and trading, coordination of flexibility actions,

quality control;

• General expenditure like insurance cost, general management and

administration;

• Intermediate services: costs with the forecast services contracted,

telecommunications, operation of ICT environment;

• Other outflows: services purchased from third parties (rent of buildings or

machinery) (if needed). In this BM1 evaluation, other outflows are not considered.

Revenues of the BM:

• Customers pay a fixed annual amount.

• The contract between the VPP and the small customer is a fixed annual amount

that customers pay to the VPP depending on the value of flexibility (the size and

availability of the flexibility) of small customers. In addition, there is an agreement

between the VPP and the small customer where the VPP pay a monthly fee to

the small customer according to the revenues from the markets. Based on D5.1

this agreement could be also dynamic since the market clearing prices vary over

time and the customer can choose when to submit bids.

Revenues from participation in the market:

• VPP manager will have an agreement with the provision of services to DSO. This

is assumed to be a monthly payment. The contract is however dynamic since the

payment depends on many factors that vary from time to time.

• VPP gains additional revenues from provision of services to BRP who aims at

reducing its sourcing cost and follows its electricity pro-gram submitted to the

TSO to avoid imbalance charges. VPP can participate in wholesale and other

open markets with the aggregated flexibility and gain revenues from the market.

3.1.4.4 Sources of financing

Possible sources of financing for VPP manager in BM1 are public contribution (in the

development phase), own capital and different type of loans. The Financial costs are

loan repayments, interests and taxes and these are total 251.607,00 € for 15 years.



3.1.4.5 Financial profitability and sustainability

The table summarise the total cost and revenues, which were introduced in the previous

section and the expected NPV. The considered time frame for the project is 15 years

and 0,289% has been used as the discount rate.

Table 5 – Total cost & revenues and ENPV.

Costs & Revenues Values

Total Initial Investment 201.280,00 €

Total Operational Revenues 1.271.970,00 €

Total Operational Costs 753.000,00 €

Total Financial Revenues 201.280,00 €

Total Financial Costs 251.607,00 €

Expected NPV (sum of the updated cash flows)

260.950,53 €

Based on the results, the expected NPV is 260.950,53 €. Thus, the positive NPV

indicates that the BM1 is profitable with the cost and revenue assumptions. The expected

NPV is achievable to VPP with around 120 homes and 80 offices. The BM risk

assessment associate with uncertainties of the BM.

3.1.4.6 Evaluation of GHG externalities

The BM doesn’t have a direct impact on GHG. Indirectly the BM increases the end-

customer motivation to install renewable generation (and thus potentially reduce GHG

emissions). Another indirect impact on GHG comes from the reduced need to use coal-

fired power plants for system balancing services.

3.1.5 BM01 risk assessment

3.1.5.1 Sensitivity analysis

The analysis of the cost and benefits is done for a generic example of a VPP.

The number of small-scale flexible loads have a significant impact on the revenues, since

the BM1 is dependent on customer small-scale flexible loads. The influence of the

number of customers to NPV is described in the figure below.



Figure 4 – Influence that changes in the number of cusotmers have, considering the NPV

evolution.

Also, the level of market prices in the future will have a considerable impact on the

revenues as well. Influence of the average flexibility prices on the NPV is described in

the Figure 5 – Influence that changes in the average flexibility have, considering the NPV

evolution.

Figure 5 – Influence that changes in the average flexibility have, considering the NPV evolution.

3.1.5.2 Qualitative risk analysis

BM1 involves a risk of lack availability of small-scale flexible loads, since the BM1 is

dependent on end-users’ small-scale flexible loads. Thus, the engagement of the end-

customer to participate in the energy community and in the VPP is required. Also, end-

customer acceptance for the DR actions and for sharing data with VPP service provider

is required. In addition, the agreement must consider issues related to the change of

ownership of small-scale load.



There is no service purchaser is a regional risk, since the DSO might do a network

investment and thus not purchasing the service from the VPP any more for specific

location. Technical requirements and acceptance of aggregated resources to provide

ancillary services (TSO) or balancing services (BRP) should be considered. In addition,

competition from other service providers might add regional risk.

Level of market prices will change in the future, which increases financial risk. Also,

profits on provision of the services for DSO, TSO and BRP may change in the future.

Technology and telecommunication risks related on the technical performance of the

system and IT risks are included in BM1. Additionally, the information exchange

requirements can be also different in different countries, which could add scalability

challenges.

3.1.5.3 Risk prevention and mitigation

Some of the risks can be prevented with communication, so that all participants are

adequately informed about the principles of the BM. They should be aware of the

possibilities but also with the uncertainties. To this BM1 to work also the customer should

receive clear benefits on joining the VPP.

Customer contracts are the most important mean for risk mitigation so that the partner

roles are clearly defined. With end-customer interfaces, the end-customer see the

(almost) real-time situation and can be in control of their own operations and assets.

The VPP owner should actively follow and participate in the market development so that

the solution is up-to-date, fulfils the latest market requirements and can adapt to possibly

new market requirements.

3.1.6 BM01 conclusions

This section has analysed the feasibility of a BM in where a VPP manager will aggregate

DER into VPP and offer the aggregated flexibility to markets. BM is dependent on the

end-user willingness to participate the VPP and on sharing of the markets benefits also

to the end-user. If BM fails on sharing the benefits and attracting and keeping the

customers, it won’t feasible in the long run.

According to the assumptions and financial analysis, the BM seems to be feasible. There

many uncertainties before this BM could be operational since there are regulatory

obstacles, uncertainty of the investment costs and risks related to future market prices

which effect then the profits that could be shared for the end-customers. If more actors

are participating the markets, price levels might be lower and price volatility might

increase. However, the need for the provision for flexibility in the future seems evident.



3.2 Aggregator flexibility provision to DSO for network management



2

Aggregator flexibility provision to DSO for network management

Local market flexibility and energy distributed resources for optimal grid management


The project aims to establish the foundations of a flexibility market and assess its benefits

of a series of stakeholders, namely the distribution grid. The project also puts the DSO

as a data manager and technical validator (TV) of this new flexibility market platform.

To assess the benefits for the distribution grid the project will be validated on Valverde

village distribution and microgrid. Valverde village is supplied by two secondary

substations, that supply around 250 customers, most of them residential. All the Valverde

clients have smart meters (SMs) installed designed according to the Portuguese

specifications and prepared to measure and record the most relevant energy-related

quantities such as energy, power, voltage, current and frequency. They also have remote

communication capabilities for network management through an advanced metering

infrastructure.

In the scope of previous H2020 projects (Sensible and InteGrid) in the LV grid three

energy storage systems (ESSs) were installed with different sizes and functionalities. In

the residential clients' domain, 50 of them were selected to receive equipment to enable

self-consumption and/or flexibility. The around 250 clients of Valverde can be divided

into 4 groups of clients where the last 3 refer to the 50 clients with equipment supplied

by previous H2020 projects:

• Static consumer – House connected to LV grid, without any device for flexibility

and load control. Even though this client has a SM install in their home, it has no

control over domestic equipment. Most of clients are part of this group.

• Load flexible consumer – House connected to LV grid, equipped with flexible

loads like electric water heater, smart appliances or smart plugs, that are capable

to offer flexibility for grid support through a home energy management system

(HEMS). With this equipment installed, this consumer allows the offer for

additional services from Market Players. HEMS exploit the benefits from home

area network interface with SM and take measurements in real time.

• Prosumer – In addition to the benefits from flexible load management, this

consumer has the capability to produce is energy for self-consumption. As a

prosumer, this client allows additional flexibility for grid support. If contracted with

an energy retailer, this client can sell over production for grid supply.



• Flexible prosumer – Adding to flexible consumption and production, this client

has the capability to extends flexibility over a daily period with energy storage

capacity. This allows the maximisation of flexibility smart management the

domestic energy behaviour and offers additional support to LV grid.

In the households, a software update will be done to the clients HEMS to achieve

integration with the LM platform.

In general terms, this project will validate the following processes:

• Possibility of receiving externally computed consumers generation and

consumption forecast data;

• Compute different and multiple optimal power flows (OPFs) for upstream and

local grid accounting with the existence of market flexibility;

• Technical validation of local energy market transactions;

• Compute local grid technical constraints (flexibility needs) and use the LM

flexibility to solve them for different time periods.


EDPD will be the responsible party for the BM project study potential implementation.


A local flexibility aggregator impacts different stakeholders, and in different ways. It

impacts the customers/producers who provide flexibility, for which they are rewarded. It

impacts network operators, because flexibility changes the electricity flows in their grids.

It also impacts suppliers, which buy and sell energy, because flexibility may lead to

deviations in energy with respect to the business as usual scenario. Finally, flexibility can

have an impact on the remaining customers, if it allows for a Distribution capital

expenditure (CAPEX) reduction.

Scope: Local, regional, national.

For the aim of the project, the scope of aggregation will be local / regional. According to

the DSO’s view, flexibility can only have positive impact on the DSO if it can be provided

at a local level, because grid constraints don’t occur uniformly across the whole grid.

Stakeholders identification and benefit evaluation.

In case aggregation at DSO level succeeds, suppliers can offer lower prices to their

customers (because the DSO will be able to reduce its CAPEX and operational

expenditure (OPEX) through the procurement of flexibility services). The DSO will be

able to better manage the Distribution grid, in this context of high renewable and EV

penetration in the grid. Customers who can offer flexibility services can have lower

electricity bills.



The DSO is expected to act mainly as a flexibility procurer to solve technical constraints.

in its network. Alternative scenarios will have to be considered, so that the most cost-

efficient option is adopted. For constraint management purposes, the DSO should, when

necessary, activate flexibility, through day-ahead or intraday markets. Forecasting tools

will also be important, to estimate the grid’s state in the short run, before choosing

whether to activate flexibility or not.


The DSO will leverage from the existent smart metering infrastructure and from the

functionalities of the advanced distribution management system and will do minor

changes to enable the use of market flexibility for long and short term and close do real-

time congestion management.




In Portugal, Distributed Electricity is approximately 45 TWh per year. Although the first

semester of 2019 has seen a slight decrease in electricity consumed, with respect to the

same period of 2018 (mainly due to the higher temperatures), the Portuguese Regulated

forecasted a growth rate in electricity consumption for 2019.

There are five main voltage levels, in Portugal: VHV (connected to the Transmission

Network), HV, MV, Special LV and Normal LV.

Regarding the structure of electricity demand, there are around 6,2 million customers.

Nearly all these customers are residential (what we designate by “Normal LV”)

customers. These customers have a nearly 40% share of total electricity consumption,

including public lighting. There are around 60.000 non-residential customers, and their

consumption represents more than half of the weight in electricity consumption.

In what concerns to electricity supply, there are more than 30 market suppliers, and there

is one major Last Resort Supplier, which offers a regulated tariff/price, set by the

Portuguese Regulator. The liberalisation process has led to an increase in the weight of

consumption supplied by the market. For 2019, the Last Resort Supplier is expected to

have an average of 1,05 million customers and a consumption share of less than 10%.

These figures are relevant, because, on the one hand, market players can increase the

alternative flexibility offers (in case suppliers choose to become aggregators). On the

other hand, considerable number of the Last Resort Supplier’s customers may allow the

Regulator to test flexibility offers through the regulated supplier. These regulatory



initiatives can be useful to incentivize the market to start offering flexibility for distribution

purpose.


hydro and wind power are the main sources of renewable generation in Portugal. In 2019

so far, renewable generation accounted for around 48% of total consumption, while non-

renewable generation represented approximately 41%. The remaining part was

imported. Also, most of the DG (which includes all renewable generation except large

hydro) is injected in the Distribution grid. Hence, renewables have a considerable impact

on the distribution network.


Future demand for electricity in Portugal is expected to have an increasing weight of

solar self-consumption. After the legislation of 2014 that framed the activity of self-

consumption, it is anticipated that, in the following months, new legislation will allow for

collective self-consumption and the creation of energy communities. Therefore, it is

expected that, in the future, there will be more prosumers at residential level, which have

a negative impact on the volume of electricity that is distributed by the electricity grid.

Another variable that is having a growing impact on distributed electricity are EVs.

Portugal was one of the countries with highest number of EV sold (more than 8.000) in

2018. This growth in EV sales has a positive impact on electricity distributed by the grid,

and EVs bring new challenges to grid management.


There are some flexibility mechanisms in place, in Portugal. There is an interruptibility

mechanism, managed by the TSO, in which the TSO can lower the load of the customers

(large customers) that joined the interruptibility scheme. Although the DSO does not play

an active role in managing this mechanism, it can request the TSO to interrupt

customers, in case it becomes necessary.

Also, the Portuguese Regulator launched, in the end of 2018, a pilot project of flexibility.

In this pilot, MV, HV and VHV customers, capable of offering a flexible load of 1 MW (or

more), can join the pilot, which targets the Global System Management in what concerns

to Tertiary Reservation.

So far, however, there have not been projects for flexibility at LV level.


The importance of tackling climate changes leads to higher levels of electrification, but

also self-consumption, renewable generation and EV sales. All these variables impact

the Distribution grid.



In Portugal, the main Portuguese DSO is EDP D, and its activity requires investing more

around 300 million euros per year in its networks. Also, there are significant amounts of

OPEX to operate and maintain the grid. Any additional tools to increase flexibility or

demand-side management can be useful and, when economically optimal, the DSO

should be able to use flexibility or other demand-side management tools rather than

increasing it costs. However, the greatest challenge is to find a model that, without being

too expensive, allows for effective OPEX and CAPEX gains. Although the level of grid

investment is significant, most of this amount is not demand-related. Therefore,

aggregation at DSO level is an activity that must meet direct and clear gains in terms of

DSO costs.

In what regards the environment there will be:

• No physical impacts on: soil, water and air;

• No biological impacts: flora, fauna and ecosystems;

In social impacts, there will be no impacts on land uses, patrimony, and people-focused

impacts such as population density, employment and hazards. In what regards societal

focused impacts there will be an impact on local electrical grids: grid losses reduction,

impact on global electrical system can be the increase in the overall system efficiency

and the impact on households can be energy savings.

As for climate change perspective, the key points might be:

• Less energy losses on the grid, thus avoiding GHG emissions from generation;

• Less centralised generation, thus avoiding GHG emissions.


3.2.3.4.1 Location

The tests will be made in the Valverde village, which is supplied by two secondary

substations. Valverde has approximately 250 customers, most of them are residential.

3.2.3.4.2 Technical Design

All the Valverde clients have SMs installed designed according to the Portuguese



communication capabilities for network management through an advanced metering

infrastructure.





BM2 is related to the procurement by the DSO of aggregator flexibility. This type of

activity has never been implemented in Portugal. Although the Portuguese demo plans

to simulate scenario where customers are subject to load changes according to the grid’s

needs, we are unable, at this stage, to quantify the benefits and costs of this sort of

solution.


The investment costs will always include a platform where flexibility offers can be made

by flexibility aggregators to the DSO to the participants they aggregate. This platform

must be certified and will require registration by all interested aggregators. Also, flexibility

participants will have to be equipped with the necessary devices that allow the

aggregator to either directly manage flexibility or communicate to the participant the need

of that participant’s flexibility. While the DSO shall be responsible for setting the amounts

and location of the flexibility needs, the aggregator must have the technological means

to give a timely response to the DSO.


Another cost has to do with market aggregators would have to collect and manage data

from the participants they aggregate. This activity may involve some system investment

costs, but also operating costs of HR for aggregators to actively manage consumption

and generation data of the participants. The flexibility platform will also require regular

maintenance cots by the IT resources, to assure its proper functioning. Finally,

commercial relations between aggregators and participants (billing, information

requests, complaints, contract management) will always require a significant amount of

OPEX spent by aggregators.

In what concerns to revenues, the activity of providing flexibility services to the DSO must

always be efficient enough, so that DSO grid expansion investment does not become a

better option than procuring flexibility services. As such, aggregators must assure an

amount of revenues that makes the activity profitable and sustainable, but, at the same

time, aggregators will have to consider that DSO shall only purchase flexibility whenever

that option is cheaper than investing in the grid.


The creation of a market platform where all aggregators and interested parties could

make flexibility offers could be part of a regulated activity by the DSO. In a similar way,

a pilot for tertiary reserve was tested in Portugal, where the Portuguese System Manager

is responsible for the platform management. In this scenario, a platform managed by the

DSO would be expected to earn a regulated rate of return and have the platform



maintenance costs accepted by the NRA. However, the ownership of a flexibility platform

will have a significant influence on the way it is financed.


Given the current inexistence of any market design for flexibility in Portugal, it is not

possible at this stage to forecast the profitability of this kind of activity.

The 2019 Electricity Directive already establishes that DSO shall procure flexibility

services to market providers when that option reveals to be the most efficient alternative.

As such, as long as aggregation and flexibility market players offer flexibility at an

efficient price, the activity of aggregation will be financially sustainable.


Flexibility offers shall internalize the impact of GHG on the costs of either procuring

flexibility or choosing to adopt conventional investment options.



The flexibility market will change according to several variables, namely:

• Flexibility platform costs (both OPEX and CAPEX);

• Regulatory rate of return on DSO investment;

• Willingness of customers to offer flexibility and resulting flexibility prices offered

by market participants;

• Aggregator activity costs;

• Number of aggregators and level of competitiveness of the aggregator market.


It will be important that the NRA plays a role in assuring how the flexibility market will

develop its activity. Although the flexibility prices should result from market interactions,

the NRA will be key to establish which entities can operate in this market, which role the

DSO can have and in which conditions customers can be aggregated.


It will be important to guarantee the customer’s trust, so that the customer is willing to

share data with the company. Data will have to be managed carefully, and technology

will have to be reliable, despite the high volume of data. The risk of being unable to

collect the data can compromise the success of grid state estimation and decisions

regarding the procurement of flexibility.



On the other hand, the customer’s experience should not be too complex, to assure a

good level of participation. Hence, the risks are related to the technology’s reliability and

to the way communication with the customer is made.

In a rollout scenario, the regulatory framework must allow the DSO to use external

flexibility to solve grid constraints.


In this chapter a qualitative analysis of the implementation of a LEFM and aggregator

flexibility provision with impact on the DSO management systems was performed. The

BM required an abstraction layer to estimate financial costs, revenues and system

benefits that the DSO, by its nature of regulated, publicly auditable and transparent

entity, is not capable or authorised to extrapolate without a public consultation and

national regulation framework that generate consensual values for OPEX, CAPEX and

system benefits.

On that sense, a qualitative analysis was performed to assess, evaluate and empower a

step-by-step implementation of a LEFM for DSO benefit. The benefits, the impacts and

the demand conditions of the flexibility provision and the aggregator participation were

evaluated, about the DSO´s systems, energy stakeholder´s role, economic and financial

challenges and opportunities, perceived system benefits and potential regulatory options

for the DSO´s OPEX and CAPEX solutions.



3.3 Using transactive energy for network congestion management



3

Using transactive energy for network congestion management

Local market flexibility and energy distributed resources for optimal grid management


The project will be validated in the Valverde village distribution and microgrid. Valverde

is supplied by two secondary substations, that supply around 250 customers. All the

Valverde clients have SMs installed and designed according to the Portuguese



communication capabilities for network management.

In the scope of previous H2020 projects (Sensible and InteGrid) in the LV grid three ESS

were installed with different sizes and functionalities. In the residential clients' domain,

50 of them were selected to receive equipment to enable self-consumption and/or

flexibility. The around 250 clients of Valverde can be divided into 4 groups of clients. The

last 3 refer to the 50 clients with equipment supplied by previous H2020 projects:

Static consumer – House connected to LV grid, without any device for flexibility and load

control.

Load flexible consumer – House connected to LV grid, equipped with flexible loads like

electric water heater, smart appliances or smart plugs, that are capable to offer flexibility

for grid support through a HEMS.

Prosumer – In addition to the benefits from flexible load management, this consumer has

capability to produce is energy for self-consumption.

Flexible prosumer – Adding to flexible consumption and production, this client has the

capability to extends flexibility over a daily period with energy storage capacity.

In the households, a software update will be done to the clients’ HEMS to achieve

integration with the LM platform.

In general terms this project will validate the following processes:

• Possibility of receiving externally computed consumers generation and

consumption forecast data;



• Compute different and multiple OPFs for upstream and local grid accounting with

the existence of market flexibility;

• Technical validation of local energy market transactions;

• Compute local grid technical constraints (flexibility needs) and use the LM

flexibility to solve them for different time periods.


Empower will be the body responsible for the implementation of this BM, although EDP

Distribuição will have a role in terms of technical validation and market enabling.


The use of TE for network congestion management will mainly concern the DSO and the

agents that provide the energy flow management tools. Although the purchase and sale

of flexibility concerns many agents, if we strictly focus on the use of that energy, then it

is related to the DSO and the TE providers. The provision of TE has a local scope, but

the use of TE will have a scope that corresponds to the DSO dimension.


The goal of BM3 is to analyse the benefits that may arise from giving the DSO the

possibility to use the energy new RES to manage congestions that may locally occur.




In Portugal, Distributed Electricity is approximately 45 TWh per year. Although the first

semester of 2019 has seen a slight decrease in electricity consumed, with respect to the

same period of 2018 (mainly due to the higher temperatures), the Portuguese Regulated

forecasted a growth rate in electricity consumption for 2019.

There are five main voltage levels, in Portugal: VHV (connected to the Transmission

Network), HV, MV, Special LV and Normal LV.

Regarding the structure of electricity demand, there are around 6,2 million customers.

Nearly all these customers are residential (what we designate by “Normal LV”)

customers. These customers have a nearly 40% share of total electricity consumption,

including public lighting. There are around 60.000 non-residential customers, and their

consumption represents more than half of the weight in electricity consumption.


hydro and wind power are the main sources of renewable generation in Portugal. In 2019



1 – https://www.apren.pt/

so far, renewable generation accounted for around 48% of total consumption, while non-

renewable generation represented approximately 41%. The remaining part was

imported. Also, most of the DG (which includes all renewable generation except large

hydro) is injected in the Distribution grid. Hence, renewables have a considerable impact

on the Distribution network.

Regarding network investment, the Portuguese main DSO invests between 250 and 300

million euros each year in its grids, to assure safety of supply, technical quality of supply,

network efficiency, operational efficiency and to give access to the customers to

innovative services. Given the low annual rates of growth in electricity consumption, the

DSO faces a smaller amount of congestion episodes, when compared to the periods of

high electrification levels. However, some variables like electric mobility or Decentralised

Generation (which is increasingly connected to the Distribution grids) can contribute to

local congestion situations which the DSO must solve, either by investing in the grid’s

capacity or, eventually, by procuring services that help the DSO manage congestions.


The increase in electricity consumption and in the generation of electricity based on

intermittent renewable sources raises the value of TE for DSO management.

According to the Energy Outlook published by the Portuguese Renewables

Associations1, electricity consumption is expected to grow at an annual growth rate of

approximately 1%, until 2030, which will result in a demand of around 58 TWh in 2030.

Regarding renewable generation, the costs of solar PV are expected to decrease:

CAPEX from 800 €/kW in 2018 to around 550 € in 2030, while OPEX should fall from 16

€/kW to 12 €/kW. In the same line, there is the onshore wind power, whose cost per kW

should fall by 20%, reaching a cost below 800 €/kW in 2030. In consequence, both Solar

PV and Wind onshore are expected to play a bigger role in the energy mix. These

technologies are intermittent but renewable, so they will raise the importance of using

TY to lower the investment needs of the DSO.


There are two major alternatives to the use of TE to solve grid congestion at DSO level:

one of them is to reinforce the Distribution network investment when there is risk of

congestion. Although this solution may sound costly, it will largely depend on the

evolution of electricity demand in the future. A scenario of low electricity consumption

growth, associated to more use of self-consumption and electricity storage may reduce,

by itself, the costs of congestion management. However, and considering the forecasted

levels of DG, EV penetration and electrification, it may be important to give the DSO as

many cost-effective tools as possible.

Another solution would be to design new pricing schemes, such as dynamic network

tariffs. Although this alternative may not guarantee the necessary load reduction levels

https://www.apren.pt/



(as they depend on the customers’ level of response) they can be an important

complement to a flexibility market.

Hence, the future of DSO congestion management may include three major options: to

invest in the grid when there is the risk of congestion; to send price signals to customers,

to optimise their use of the grid; to buy/sell flexibility through TE.


Although flexibility may be used to maximise the share of RES in the energy mix, it is

less clear to find a direct connection between flexibility at DSO congestion management

level and climate change. However, and although this variable may not assume a

significant value, flexibility at DSO has the potential to curtail consumption in peak hours

and, in consequences, the level of technical network losses. Despite this theoretical

impact, it is unclear whether the reduction in network losses through peak-shaving

actions would be significant.



The use of TE to solve network congestion issues is not yet an implemented or tested

model in Portugal and, as such, this analysis will be based on the best-known information

regarding the challenges, costs and revenues that this activity can have in the future.

Also, as this BM has not been fully implemented, we are unable, at this stage, to quantify

the financial impact of implementing BM3.


The use of TE will require an advanced database where the DSO can identify where

offers are available and which amount can be offer in each moment. Also, all players

capable of offering these services must qualify to do so and be equipped with the

necessary devices to allow the DSO to request their services. From the DSO side, the

challenge will be to have real-time or near real-time visibility of the network, to identify

any congestions in the grid. Given the granularity of the LV grids, it is probable that there

would be too high investment costs to monitor grid congestions at LV level.


The main operating costs would be related to HR capable of monitoring the grid’s status

at the different voltage levels and support the decision-making process to procure

services that help the DSO manage any potential congestion.


The DSO should have the regulated costs of this activity recognised, and this option shall

only be adopted when none of the alternatives is more efficient. The DSO should have



its investment recognised and rewarded with the regulatory rate of return and have

service procurement costs accepted by the NRA.


In what concerns to congestion management support providers, their financial

profitability should result from the market interactions. Regarding the profitability of the

DSO, it is expected that the DSO will find this alternative cheaper than any other and, as

such, the choice to procure these services should earn a return below the investment

regulatory rate of return.

The more the congestions in the DSO grid, the more space there will be for the DSO to

procure congestion management services. That is, the sustainability of this model

depends on the impact of new resources, such as batteries, self-consumption, EV or

renewable generation at Distribution level on the grid’s capacity.


The use of congestion management innovative solutions can have a positive impact in

terms of GHG emissions, particularly if they increase the DSO’s capacity to connect

renewable generation.



Flexibility contracts go beyond the scope of DSO grid congestion management.

Regarding only this impact, it is important to run a deep analysis on the real

reinforcement investment needs of each DSO. These can significantly vary according to

the country, for example, because the technological level and roll-out of certain tools –

such as self-consumption, batteries or EV – is variable.


Any flexibility contract implies a reward to the flexibility provider, which must meet the

corresponding cost reduction. This cost reduction at DSO level must be well estimated,

to assure value-for-money choices.


In case the grid has low reinforcement investment needs (that is, in case the grid has a

small number of congestion situations), there is the risk that flexibility to manage DSO

grid congestion becomes a non-attractive activity.

Extensive CBAs should be made, prior to the implementation and during pilots or tests,

to correctly estimate the gains of TE for DSO grid congestion management. Another



aspect that must be considered is a proper diagnosis to the grid’s state, to identify the

real congestion-related investment needs of the grid, in the future.


In this chapter a qualitative analysis of how the TE and the implementation of LEFM

could impact on the DSO management system and the grid optimisation was performed.

The BM required an abstraction layer to estimate financial costs, revenues and system

benefits that the DSO, by its nature of regulated, publicly auditable and transparent

entity, is not capable or authorised to extrapolate without a public consultation and

national regulation framework that generate consensual values for OPEX, CAPEX and

system benefits.

On that sense, a qualitative analysis was performed to assess, evaluate and empower

an implementation of a LEFM for operational and grid benefits. The benefits, the impacts

and the demand conditions of the flexibility provision, the technical validation, the market

relationship between DSO, market parties and consumers were evaluated about the

potential economic and financial investment and revenue conditions.

The perceived system benefits and the potential regulatory options for the DSO´s OPEX

and CAPEX solutions are still under a broad, disperse and non-consensual discussion

at local and European level by NRAs, TSOs and DSOs about distributed or centralised

technical validation of such market options. Although, some considerations and

inferences about the challenges and opportunities are analysed and stated in this BM.



3.4 Sharing the exceeding PV generation in the scope of energy communities



4

Sharing the exceeding PV generation in the scope of energy communities

Local community market with flexibility and energy asset management for energy community value


In this BM, a CM acts as an aggregator of prosumers and consumers with generation

assets (primarily solar PV) and DR capability, providing the technological platform to

facilitate local sharing and trading of generation. The CM staff should be able to promote

the utilisation of the resources locally and ensure the existence of the required flexibility

platform. The platform can either be contracted as a third-party resource or developed

in-house. Services like load and generation forecasting can also be provided as internal

development or supplied by external parties.

The CM should establish contracts with consumers and the market to take optimised

management of the PV and DR. In addition to the technological sharing platform, the CM

may have direct load control capabilities to accomplish automated DR. In addition,

consumers may have HEMS to execute local transactions with other community

members. The key asset utilised in the BM is the local generation. Existing generation

assets of the community members may be utilised or alternatively the CM may assist in

the investment and construction work as a part of the service.


This BM is meant for a CM. Such role may be adopted by a company with expertise to

develop and/or manage an ICT platform and assist in generation investment planning.

In principle, also an energy retailer could adopt the CM role, but this analysis focuses on

an ICT and energy management specialist company viewpoint.


The scope of this BM is mainly local. Although energy sharing does not require a local

community (i.e. the community may be also virtual), the benefits may be larger and apply

also to DSO when local demand and supply are matched. Local community is more likely

to drive participation of public buildings and reinforcement of local solidarity.

The energy community consisting of consumers and prosumers will benefit through

reduction in energy bills, increased green self-consumption, and compensation for

surplus energy. The more detailed benefits for each stakeholder related to the BM are

presented in the table below.



Table 6 – Benefits for different stakeholders.

STAKEHOLDER ROLE ACTIONS AND BENEFITS

COMMUNITY OF

PROSUMERS AND

CONSUMERS

Customer Optimal DR scheduling and sharing of PV generation among the

community is provided aiming at the reduction of bills and green self-

consumption.

The technological platform is provided by the community manager who

may also have direct load control capabilities (members may also have

HEMS)

PROSUMERS Provider Sell excess generation and receive compensation for it

The consumers providing DR will receive the benefits of PV in the

proportion of the contribution made by DR, as a discount in their bills.

COMMUNITY MANAGER Provider CM provides DR and PV to the community.

The service will be paid as a fixed fee to the CM or aggregator.

The CM will also receive a fee for the service paid by the community

members. Also, the DR and energy delivered to the market will be paid

to the CM so it can share some incomes with the community.

DSO Customer Congestion management

The stakeholders involved in the BM are presented in Figure 6.

Energy community

CONSUMERCONSUMERCONSUMERCONSUMER

PROSUMERPROSUMERPROSUMERPROSUMER

PRODUCERPRODUCERPRODUCERPRODUCER

Community manager

Sharing of PV generation

PV generation

Figure 6 – Business model stakeholders and relations – reported in D5.1.



Table 7 presents the necessary contracts related to BM4. C1 is the subscription contract

between CM and community member, C2 is a contract between CM and each customer

with PV generation, and C3 is a contract between CM and each consumer with DR

capabilities.

Table 7 – Summary of the contracts for BM4.

C1 C2 C3

Stakeholders

CM ✓ ✓ ✓

Community members ✓

Customers with PV generation ✓

Consumers with DR capabilities ✓

Type Dynamic ✓ ✓

Static ✓

Payment Type Monthly ✓ ✓

Annual ✓

Pricing

Action Base

Static ✓

Incentives ✓

Dynamic ✓


BM4 relates the following objectives of the DOMINOES: design and develop a LM

concept that:

• Empowers prosumers to decide on the distribution of value of their energy

resources;

• Enables local sharing and optimisation of renewable resources in MV and LV

grids.

More precisely, the objective of BM4 is to provide a service that enables a community of

energy consumers, producers, and prosumers to share the PV generation exceeding

their consumption instead of delivering this energy to the grid.




The amount of generation installed in distribution networks is increasing in Europe. In

2018, solar power covered only about 0,2% of the Finnish electricity generation [14].

However, it is the most important small-scale generation technology. At the end of 2018,



the aggregated capacity of grid-connected small-scale power generation (units below 1

MW) was about 201 MW and solar PV accounted for 60% (120 MW) of this [15].

Furthermore, compared to 2017, PV capacity had increased by 82%.

In Portugal, solar power accounted for 2% of the electricity generation in 2018 [16]. The

aggregated capacity of micro (<3.68 kW) and mini (3.68–250 kW) PV systems has

increased from 10 MW in 2008 to near 174 MW in 2016 [17].

Thus, the consumers’ interest in and amount of small-scale generation is increasing

rapidly in case of countries (and globally), creating opportunities also for energy

communities. However, services for such communities are not yet commonly offered as

the regulatory framework in many countries does not acknowledge them.


Most countries are striving to decarbonize their energy systems which will require

investments in renewable power generation. For example, in Portugal, the installed solar

capacity is forecasted to raise significantly in the following years. The forecast for 2021

is 1684 MW, forecast for 2025 2923 MW and forecast for 2030 4973 MW [16].

In addition to the general trend towards power systems based on renewables, the role

of local assets and local trading is likely to increase. The Clean Energy for All Europeans

package and especially the Directive (EU) 2019/944 [7] on common rules for the internal

market for electricity and Directive (EU) 2018/2001 [2] on the promotion of the use of

energy from renewable sources introduced the terms ‘citizen energy community’ and

‘renewable energy community’ and set requirements for their rights and regulatory

framework related to them. Once implemented into national legislations, they can be

expected to boost the development of energy communities and thus create a need for

services for the communities.

Enabling the sharing and trading within communities will help unleash the PV potential

in new types of buildings. For example, it has been estimated that the technical potential

of PV in Finnish apartment buildings could be between about 0.95 and 1.3 GW [18]. The

difference in estimates is explained by differences in assumptions and statistics used.

Nevertheless, the potential in apartment buildings alone is considerably higher than the

current installed capacity. Due to the increase in DG and developing legislation, the

interest in services facilitating energy community creation and operation can be expected

to increase.


The options for energy sharing within communities differ according to national

frameworks. In the worst case, prosumers are not able to share their excess generation

nor get any type of reimbursement for it. Thus, without sharing or trading the PV or other

generation unit would be dimensioned according to individual customers (e.g. detached

house, condominium’s shared use such as corridor lighting).



In Portugal, the former self-consumption rules (Decree-Law No 153/2014 [19]) allowed

renewable prosumers with capacity not exceeding 1 MW to make a contract with the

supplier of last resort for their excess generation injected to the grid. The remuneration

was set at 90% of the OMIE monthly average price for Portugal. In October 2019, new

legislation regarding self-consumption was published. According to the Decree-Law

162/2019 [8], the surplus energy may be traded in organized markets and through

bilateral contracts. The price paid for the surplus can be freely negotiated. Furthermore,

the Decree-Law allows also collective self-consumption, i.e. same production unit may

have several self-consumers.

In Finland, there are currently no feed-in-tariffs or other legislated schemes for small

scale generation. However, some retailers buy the excess generation of their customers

at the spot price (Nord Pool Spot price for Finland, minus a possible service fee). The

requirements concerning energy communities defined in the Clean Energy for All

Europeans packages are yet to be transposed. Draft legislation – [20] – to enable

communities and energy sharing within a property was circulated for comments in spring

2020.

Thus, the main alternatives for sharing/trading generation within the community are

producing only for own needs or selling the excess to external markets e.g. via the

retailer.


The BM is not expected to have physical impacts on soil, water and air, nor biological

impacts in flora, fauna and ecosystems. As the generation and control equipment are

installed within existing buildings (e.g., rooftop PV), the negative environmental impacts

are mainly limited to the manufacturing of the equipment. The service is mainly ICT

based and is not expected to have major impacts on climate change.

However, the opportunity to share generation and receive compensation for excess

generation may increase the willingness to install larger generation units (i.e. not only

according to own loads) and thus increase the amount of renewable generation capacity

as small-scale generation often relies on solar power. Furthermore, better abilities to

balance demand and supply locally may contribute to smaller reserve power needs. As

reserve plants often use fossil fuels, balancing the demand and supply locally may help

cut emissions of the power system.


BM4 is not directly linked to any of the pilot sites of the project. The analysis is based on

a generic case example mainly from a Portuguese viewpoint as Portugal already has

adopted legislation concerning communities. However, once the energy community

legislation is clarified, similar BMs could be adopted in other countries also.





This BM considers the viewpoint of a CM, i.e., a service provider facilitating the local

sharing of generation. The community members are assumed to have a separate

contract with retailers that supply the consumption not covered by community generation.

The generic example community used in the analysis consists of the following members

with differing load profiles:

• 2 medium C&I customers;

• 2 supermarkets;

• 20 small offices;

• 200 homes.

1000 kWp PV generation is acquired for the community (i.e. no pre-existing PV) assisted

by the CM. 87% of the solar PV generation is used within the community and the rest is

sold to the grid.

Due to confidentiality, detailed values of some cost and revenue components are not

included in the report. The analysis is done for a 15-year project/service duration.


Initial investment includes the PV investment consisting of the solar panels, inverters and

related construction work. The total initial investment is assumed to be 780.000,00 €.

The necessary ICT platform is contracted via an external service provider and included

in the operating costs.

The BM presents a new type of service and is not considered to replace any existing

infrastructure. Thus, replacement costs and residual value are not considered.


The operating costs considered include the license fee for the ICT platform, personnel

costs for the operation of the ICT platform, operation and management of the PV, grid

costs and the payments for the external forecast provider. The total annual operating

cost consisting of the above-mentioned components is assumed to be about 136.500,00

€ and the total costs during the project lifetime are about 2.047.000,00 €.

Revenues include the fixed service fees from the community members, revenues for

selling community energy to the members, and revenues for selling the community

surplus to the grid. The total annual operating revenue consisting of the above-

mentioned components is assumed to be about 251.200,00 € and thus, the total

revenues during the project lifetime are about 3.768.000,00 €. This leads to net

operational revenues of 1.721.000,00 € during the project lifetime.




The needed investments are financed through bank loans (73%) and an investor (27%).

The financial revenues match the initial investment cost 780.000,00 €.


Table 8 summarises the total cost and revenues, which were introduced in the previous

sections and the expected NPV. The considered time frame for the project is 15 years





Total Operational Revenues 3.767.678,56 €

Total Operational Costs 2.046.618,71 €


Total Financial Costs 1.037.534,56 €


1.442.596,58 €

The positive NPV indicates that this BM, in which a CM facilitates energy sharing within

a community, is profitable when serving the defined generic case community, and with

the cost and revenue assumptions made. Due to the novelty of the service offered to the

communities, and the novelty of the services the CM needs to serve the community,

there are many uncertainties which will be discussed in the sensitivity analysis.


The service proposed in this BM is mainly IT-based and the impact on the GHG

emissions depends on: i) whether consumers decide to install more renewable

generation due to the availability of the service and; ii) what kind of generation it possibly

replaces. Nevertheless, the BM is likely to contribute to GHG reduction as the BM also

encourages matching of local demand and supply, thus reducing losses in transmission

and distribution.





This sensitivity analysis focuses on five aspects. Firstly, as this is a novel service, it is

difficult to assess customers’ willingness to pay for it. Thus, the first variable whose

variation is considered is the level of the fixed service free charged from the community

members. Secondly, the BM relies on the availability of the ICT platform services and

price of such service. Thirdly, the personnel costs are varied as 1) the amount of work

depends on the quality and characteristics of the ICT platform, 2) personnel costs are

not necessarily directly linked to the number of communities served, and thus, decrease

in the number of served communities may increase the personnel costs per community.

Fourthly, the PV investment should be planned based on the members and

characteristics of a certain community. If members would for some reason be lost after

the investment, it will reduce the amount of generation that can be consumed within the

community. Finally, the discount rate used in the initial analysis is rather low, reflecting

today’s situation. Because the initial investment in this BM is considerable, influence of

variations in discount rate is considered.

Figure 7 – Influence that changes in the level of service fee from the community members

have, considering the NPV evolution.

€1 442 596,58

€1 293 076,76

€1 143 556,93

€0,00

€200 000,00

€400 000,00

€600 000,00

€800 000,00

€1 000 000,00

€1 200 000,00

€1 400 000,00

€1 600 000,00

Base rate 50 % lower No fee



Figure 8 – Influence that changes in the ICT platform licence fee have, considering the NPV

evolution.

Figure 9 – Influence that changes in the personnel costs have, considering the NPV evolution.

€1 442 596,58 €1 339 984,94

€1 237 373,30

€0,00

€200 000,00

€400 000,00

€600 000,00

€800 000,00

€1 000 000,00

€1 200 000,00

€1 400 000,00

€1 600 000,00

Base rate forplatform

100% higher 200% higher

€1 442 596,58

€1 105 444,04

€768 291,49

€0,00

€200 000,00

€400 000,00

€600 000,00

€800 000,00

€1 000 000,00

€1 200 000,00

€1 400 000,00

€1 600 000,00

Base rate 50 % increase inpersonnel costs

100 % increase inpersonnel costs



Figure 10 – Influence that loss of certain customers has, considering the NPV evolution.

Figure 11 – Influence of the changes in the discount rate used in analysis, considering the NPV

evolution.

For the kind of community used in the analysis, the variations in the analyses still lead to

positive NPV. However, especially increased personnel costs and changes in the

community members after the initial investment have a large influence on the NPV. The

latter emphasizes the importance of the correct dimensioning of the PV system as the

benefits for both the CM and the community are largest when most of the generation can

be consumed within the community. In the estimated base case, 87% of the PV

generation is consumed within the community. With the similar PV system but only one

industrial customer, the self-consumption rate would decrease to 63%, whereas losing

one industrial customer and 50 households would lead to a self-consumption rate of 58%

and to a 50% lower NPV than in the base case.

€1 442 596,58

€1 091 820,36 €1 077 136,97

€707 582,30

€0,00

€200 000,00

€400 000,00

€600 000,00

€800 000,00

€1 000 000,00

€1 200 000,00

€1 400 000,00

€1 600 000,00

Casecommunity

Casecommunity -50 residential

Casecommunity - 1

industrialcustomer

Casecommunity -50 residential

and 1 industrial

€1 442 596,58

€1 225 336,58

€1 066 975,90

€0,00

€200 000,00

€400 000,00

€600 000,00

€800 000,00

€1 000 000,00

€1 200 000,00

€1 400 000,00

€1 600 000,00

Base rate Discount rate 4% Discount rate 8%




The main risks related to the BM relate to regulation and legislation, customer retention,

and the suitability of communities for such service. Risks in each category are listed

below.

Regulatory risks:

• Regulatory framework surrounding energy communities is still under

development in most countries. Now, regulation may not yet enable energy

sharing at all.

• Some countries have regulated compensation for excess generation. If it is high,

it may decrease interest in energy sharing within the community.

Customer retention:

• Competition from other service providers (including also e.g. retailers who

already have an established relationship with end-users) is likely to occur once

the regulatory framework is clarified.

• Changes in ownership or occupancy of buildings (will new owner/occupant want

to be part of the system) are a risk for the continuance of the service.

Adequacy of generation to share/Need for the services:

• Is there enough excess generation to justify the costs of the service?

• DSO’s network investments may reduce the need for services from communities.


Potential risk prevention measures for each risk category are described below.

Regulatory risks:

• Careful follow-up of the regulatory development and communication with

regulators and legislators on the benefits of community services and potential

barriers for providing them

Customer retention:

• Long enough contracts with customers (but probably not solution if

ownership/occupancy in the participating buildings changes)

• End-user engagement activities including regular reports on service impacts and

benefits for the community

Adequacy of generation to share:

• Analyses of potential generation and self-consumption before signing contracts

• Assistance in suitable generation investments for the community




This section has analysed the feasibility of a BM in which an energy management

specialist company acts as a CM enabling sharing of excess generation within the

community and assist in the generation investment. Such role is new in the energy sector

and its realization depends on an enabling regulatory and legislative framework which is

still under development in many countries but should emerge soon due to the

transposition of the requirements of the recast electricity and renewable energy

directives.

With the cost and revenue assumptions used in the analysis, the BM seems feasible.

However, the BM relies on outsourced ICT and forecast services and thus their

availability and costs impact the profitability of the BM. Furthermore, changes in the

community members after the initial investment can have large impact on the profitability

of the BM. Thus, it is important to engage the customers before any generation

investments are made and also if ownership or occupancy of the participating

buildings/companies changes.



3.5 Retailer as user of the local market



5 Retailer as user of the local market

Local community flexibility and energy asset management for retailer value

BM5 defines a business case in which a retailer has access to the LEFM and uses locally

purchased energy or flexibility to solve imbalances in its portfolio or to optimise its

wholesale market participation. This BM is described in D5.1, and the associated UC –

local community flexibility and energy asset management for retailer value is presented

in D1.3.


This BM takes advantage of the local ecosystem, i.e., a microgrid environment, a local

community within a distribution grid environment or a VPP environment, promoted by the

accessible marketplace. Regardless of the exploitable environment, apart from the

foreseen physical, human capital, organisational and digital resources required to set up

the LEFM, and from the provided services for forecasting, aggregation and market

interface, already identified in the characterisations of the previous BMs, this BM does

not require additional add-ons.

The required market interfaces, that will allow the retailer to interact with the LEFM

platform, to monitor the LM prices and bid for the required energy/flexibility aggregated,

is perhaps the key enabler. The ICT platform and the market interfaces represent the

initial investment the retailer must support to ensure the market access and the desirable

upstream/downstream interactions to leverage their operational management focused

on portfolio optimisation.


The main stakeholders involved are the retailer and the service provider, i.e., the LM

operator.

Since the BM is mainly focused on the retailer’s perspective and how to extract value

and benefit from engaging at the LEFM level, CNET, representing the utility’s and

particularly the retailer’s interest in LEFM on behalf of the EDP Group, will be responsible

for the implementation of this BM.


Scope

BM5 has a wider scope than some of the other BM considered. The local scope is mainly

related with the impact that the retailer’s local procurement of energy and flexibility may



have on the LEFM dynamics, since depending on the LM conditions, i.e., daily amounts

of available energy and flexibility, but also on the wholesale prices and the imbalances

cost, the retailer’s bids may influence the price at the LM.

The BM impact at regional and national level is mainly linked to the direct influence the

activated transactions may have in the system’s operation, due to the possible changes

in the power flows that must be validated by the SOs, and in the upstream markets’

interactions, since the magnitude of the aggregated energy/flexibility locally mobilised

may influence day-ahead and intraday wholesale market activity.

Stakeholders identification and benefit evaluation

Figure 12 shows the stakeholders involved in this BMs, and the 3-level BM framework is

presented in

Table 9.

WS and LM(Day-ahead,

Intraday, Balancing)

RETAILER

Energy community




RETAILERRETAILER Flexibility

Marketparticipation

Figure 12 – Stakeholders and relations in BM5 – reported in D5.1.

Table 9 – Complete framework, BM5 – reported in D5.1.

First Level: Strategic Level

Provider - who? Flexibility available from consumers, prosumers, producers, DER and other actors playing in the local market. The flexibility will be made available through the local market operator

the strategy model - why? Retailers can access the local market flexibility for optimising their market participation in the wholesale market (day ahead and intraday) taking into consideration the fluctuation of energy prices throughout a day and the minimisation of imbalances.

the resources model - with who and what internally?

Consumers, prosumers, producers, and other actors playing in the local market as flexibility providers;

DSO to validate the transactions (technical validation taking into consideration the grid constraints);

Local market operator to negotiate the requested flexibility with the retailer



the network model - who externally?

Metering system providers, metering device manufacturers, app/consumer interface providers, Appliance/generation/control technology providers, ICT companies

Second Level: Customer and Market Level

the customer model - to whom?

This Business model is focused on the retailer

the market offer model - what?

Use of the local market flexibility to be valued in the wholesale market or to optimise the retailers’ portfolio

Potential competitors: Aggregators or other retailers

the revenue model - how they pay?

1. Revenues from optimising the participation in the wholesale market.

2. Revenues from reducing imbalances in the retailer’s portfolio.

Third Level: value chain level

the delivery model - how we deliver?

The flexibility provided by the local market shall be used by the retailer when it may have more value to economically optimise the sourcing of energy in the day ahead scenario. In the intraday, the flexibility can be used to reduce imbalances.

The retailer shall use forecasts and a platform to analyse the different scenarios and to interface with the different markets

the procurement model – how is being delivered to us?

Platform development or acquisition to platform providers; procurement of the flexibility through the local market.

the financial model – how we pay for it?

Retailer should pay for the allocated flexibility. Subscription fee to participate in the local market; Development and operation of the retailers’ platform to operate and interface with the different markets. HR costs.

This BM foresees the establishment of a contract between the retailer and the manager

of the LEFM. The available energy and flexibility to be traded on a day-ahead or intraday

basis is the commodity the retailer is interested in, to optimise the energy sourcing at the

wholesale market and minimise the incurred intraday imbalances. There are no contracts

between the retailer and the individual local providers, i.e., the flexible consumers and

prosumers. The LEFM manager will be responsible for managing the available energy

and flexibility, and from the retailer’s point of view, he acts as an aggregator with whom

he is contractually related through his LEFM engagement. The functioning of the LM is

not relevant to this BM, as the retailer is only interested in a certain amount of aggregated

energy/flexibility that will be directly negotiated with the LEFM manager.

Table 10 characterises the type of contract established between the service provider and

the retailer. It’s a dynamic contract, since the value of the traded commodity varies

throughout the day according to LM conditions. Moreover, the value that the retailer is

willing to pay will depend on the wholesale prices and the imbalances cost.



Table 10 – Summary of the contracts for BM5 – reported in D5.1.

C1

Stakeholders Retailer ✓

Service provider ✓

Type Dynamic ✓

Static

Payment Type Monthly ✓

Annual

Pricing

Action Base

Static ✓

Incentives

Dynamic


This BM aims to validate the use of the LEFM by the retailer, whose goal is to optimise

the participation in the wholesale market and minimise the daily incurred deviations.

The objective of this BM is to assess how retailers can take advantage of the energy and

flexibility aggregated and made available at the LEFM on two complementary scenarios:

1. The day-ahead energy sourcing optimisation, reducing retailers’ costs from day-

ahead wholesale participation by accessing LEFM and purchasing cheapest

energy and flexibility, optimising the portfolio;

2. In an intraday timeframe, minimise the deviations, reducing the costs incurred to

mitigate imbalances by activating cheapest energy and flexibility aggregated at

local level.



3.5.3.1.1 Current future demand

Retailers’ current demand for alternative ways to access and use aggregated energy and

flexibility to manage their portfolio and optimise their market participation is not yet

significative, mainly due to some lack on legal context framing the constitution and

operation of LEFMs either promoted at the microgrid, local energy community or VPP

level.

Nevertheless, LEFM and the services they provide may influence the retailer’s

operational paradigm, since they may lead to a non-neglectable reduction in the



operational cost by providing access to energy and flexibility requiring lower activation

prices.

The energy and flexibility activation prices available at the LEFM level are the key

enabler of the BM scale-up. Since the regulated activity for buying and selling electrical

energy implies the acquisition of electrical energy to supply a certain portfolio of end-

users, the retailer’s buying portfolio is compared to the demand portfolio and the

deviations are determined. These imbalances are solved through a settlement process

with the global system manager. For each hour of the day, the retailer must acquire the

amount of energy matching the demand expectation from the consumers with whom it is

contractually linked.

In Portugal is estimated that to respond to the demand from the 5.3 million consumers

contractually engaged with the liberalised retail market, the energy providers will need to

purchase approximately 44TWh of electrical energy during 2020 [21]. Considering the

amounts involved and the annually impact that all the required transactions for day-

ahead portfolio optimisation and intraday imbalances settlement have in retailers’

operation, active engagement in LEFM might bring significant benefits linked to the

access to advantageous LM conditions and more competitive prices.

The evolution of the business context addressed in DOMINOES’s BM5 will also depend

on the specific value the commodity has for the involved stakeholder, in this case, directly

related to the prices’ evolution for energy and flexibility in local marketplaces and the

retailers’ necessity to balance and optimise its daily portfolio.

Is expected that the above-mentioned transition will be significantly shaped by the

following trends:

• Evolution of the local/national regulations or other changes required to frame and

regulate the LEFMs’ concept;

• Growth of suitable environments to foster a LEFM, such as microgrids, energy

communities and VPPs;

• Development of suitable resources who could be aggregated and connect to a

LEFM;

• Evolution of the prices available at the LEFMs;

• Growth of the need for balancing services for deviations settlement in retailers’

portfolios;


Currently the available alternatives for the retailer’s portfolio optimisation and unbalances

settlement are provided by: the engagement in the day-ahead and intraday sessions

available at the wholesale market; and the possibility to establish bilateral agreements

with flexible end-users, mainly heavy consumers, which might be willing to change their

energy consumption profile for a certain period to match the supplier necessities.



The energy supplier can also propose to its clients to engage in DR schemes or to sell

their exceeding DG and become flexible consumers or prosumers.


Regarding the local environments proposed for the validation of BM5 there will be no

physical impacts on soil, water and air, no biological impacts in flora, fauna and

ecosystems.

As for climate change considerations some relevant points might be highlighted. The

BM5 promotes a generalised increase of the local system’s efficiency, by contributing to

the reduction of power losses and to significant energy savings, favouring decentralised

generation from RES thus avoiding GHG emissions and a more efficient use of

resources.

Concerning the socio-economic impacts, there will be nothing relevant to consider

regarding land use and patrimony, significant changes in population density and

employment. However, an important socio-economic aspect must be mentioned, since

BM5 frames the possibility for the retailer to take advantage of an active participation as

a procurer of the resources available at the LM place, contributing to the value creation

at the community level.



The context of the proposed CBA, over the BM5, considers the context provided by the

implementation of the LEFM within the scope of DOMINOES. As already described, the

retailer, as user of the LM, aims to gain access to the LM and benefit from low-cost

energy/flexibility available to optimise the wholesale participation and minimise the

incurred deviations, to be solved in the intraday operation.

Thus, the specific context of the distribution grid environment considered for the

implementation of the LEFM at the community level is crucial to fully characterised the

present analysis. The narrative of the BM and associated UC describes all the technical

details and the fundamental constraints to consider in the CBA.

According to D1.3, the retailer will not establish a contractual relationship with the active

participants of the LM, i.e., with the participants offering energy/flexibility. Instead, the

retailer directly contacts the energy community service provider (ECSP), responsible for

managing the LM activity, to request in advance the information about the amount of

flexibility available and the process expected – forecasted – for each day. This info is

key to prepare both day-ahead and intraday operations. Based on the presented

conditions the retailer decides whether he will make use of that flexibility to optimise its

portfolio.



The associated KPIs target the annual amount of flexibility activated at the LEFM for

energy sourcing optimisation and deviations minimisation, considering volume – MWh

per year – and price – €/MWh – as indicators – reported in D1.3.

Additionally, some baseline conditions must be established. The connection to the spot

market is assumed, since we are targeting well established energy providers.

The main actors involved in the UC associated to this BM are the energy providers, i.e.,

the retailers engaged and acting in the LM sessions, interested in purchasing

energy/flexibility from the LEFM, the ECSP, as manager of the LM, and the wholesale

market, the liquid electricity market where the retailer wants to optimise its participation

in the two different time frames. The two scenarios considered, and their related

conditions, also presented in D1.3, and focus the day-ahead and intraday operation of

the retailer, for energy sourcing optimisation in the wholesale market before the operating

day, accessing the consumption and generation forecasts for its customer portfolio, and

correction of deviations from the day-ahead plan, whenever a deviation is detected, to

minimise the imbalances incurred.

The steps for the day-ahead operation are: the forecasting of consumption and market

conditions for the coming operating day; the energy/flexibility request to the ECSP for

energy/flexibility from the LM; the price information; the energy/flexibility activation; and

the optimisation of the energy sourcing in the wholesale market based on the

energy/flexibility allocated at the LM.

The steps for the intraday operation are: the continuous verification of deviations in the

retailer’s portfolio; the energy/flexibility request to the ECSP and the price information;

the energy/flexibility activation; and the deviations compensation.

The general requirements to consider are: the day-ahead forecasts on the portfolio’s

combined consumption; the day-ahead forecasts on the market conditions,

energy/flexibility prices available at the wholesale and LMs, and the connections to the

local and to the spot market.


The investment costs considered target the initial investment, e.g., on start-up and other

related technical costs, logistic costs with buildings and equipment. However, for the

CBA over the BM5 the required CAPEX is not significant, and thus is not considered,

since we are focusing the CBA over the particular context proposed for the DOMINOES

project, were the business analysis is performed in the perspective of medium to large

energy providers, well established in the geography framing the LEFM, and thus not

requiring relevant initial investments to establish a dedicated operational context.

Other general expenditures related to market access, e.g., registration, accreditation,

licensing and fee, or to the acquisition of the required systems, e.g., ICT platforms related

to licenses, to interact with the LM are considered into the LEFM dedicated OPEX.




Costs

• Costs with market access, e.g., registration, accreditation, licensing and fee, to

participate in the LEFM;

The following approach was considered to assess this type of cost.

The market access costs are incurred by any energy provider aiming to be engaged and

actively participate in the LEFM. From the retailer’s perspective, the required registration,

accreditation and licensing must be addressed as an annual prequalification, that may

be diluted into the value for the OPEX per customer consider every year.

To value this cost, a percentage of the retailer’s OPEX to be depreciated is considered.

The estimation of this value considers a per-annum per-customer operational cost

estimation – retailers’ annual OPEX divided by the number of end-users served –,

bounded by pre-established lower and upper values.

Regarding the market access fee, a payment based on a certain percentage of the

retailer’s yearly revenues from activating energy/flexibility available at the LEFT for its

day-ahead and intraday operation can be considered, or, alternatively considering the

number of clients reached through the LEFM or the yearly average energy/flexibility

mobilised or available at the LEFM.

For both alternatives, the fee variation should be limited by predefined maximum and

minimum limits established every year, e.g., based on the forecasts.

• Costs with the ICT platform license or acquisition, to interact with different

markets (upstream/downstream) and assess the scenarios;

Two approaches were considered to assess this type of cost.

The retailer uses its legacy systems and a new interface to connect with the LEFM

platform, depreciating over the years a percentage of the implementation costs.

The retailer uses a new dedicated system, ensuring the connection with the LEFM

platform, depreciating over the years the acquisition costs.

Both approaches may consider, e.g., the number of clients reached through the LEFM

interface or dedicated system, respectively, or the yearly average energy/flexibility

mobilised or available at the LEFM.

Again, since the CBA focus the context proposed in DOMINOES, the perspective of a

medium to large retailer is to be considered, a player well established and not requiring

a significant investment to access and interact with both, the local and the spot market.



For this reason, the first approach is to be considered in the CBA performance over the

BM5.

To value this cost, a percentage of the retailer’s OPEX to be depreciated is considered,

diluted into the value for the OPEX per customer. The estimation of this value considers

a per-annum per-customer operational cost estimation – retailers annual OPEX divided

by the number of end-users served –, bounded by pre-established lower and upper

values.

• Costs with human-resources for the ICT platform operation, to interact with

different markets (upstream/downstream) and assess the business scenarios –

operational needs (day-ahead and intraday), day-ahead markets’ conditions,

resources’ availability (energy/flexibility) and prices;

The following approach was considered to assess this type of cost.

The retailer uses its human-resources to operate the system and interact with the LEFM,

depreciating over the years a percentage of its operational costs based on the allocation

rate – the human-resources are not fully dedicated to the operation in LEFM.

This approach considers, e.g., the number of clients reached through the LEFM or the

yearly average energy/flexibility mobilised or available at the LEFM.

Again, to value this cost, a percentage of the retailer’s OPEX to be depreciated is

considered, diluted into the value for the OPEX per customer. The estimation of this

value considers a per-annum per-customer operational cost estimation, bounded by pre-

established lower and upper values

The figures to be used, based on the research performed and presented, consider the

general costs in a year with supplies, external services and personnel costs, divided by

the portfolio of customers on a typical electricity retail business, providing an

approximated measurement over the retailer costs/customer/year.

Research on costs valuation

The following research aims to explain the rational for the valuation of the costs

presented above, based on the assumption that considers the dissolution of these costs

into the value of the retailer’s OPEX per customer, to use in the proposed CBA.

OPEX, including costs with supplies, external services and personnel costs, divided by

the portfolio of customers on a typical electricity retail business provides an approximated

measurement over retail costs and margins.

Hereupon, to assess some of the most plausible indexes to consider, an extensive

research was performed, targeting more open markets where the electricity retail

business is more diverse and therefore it is easier to value the operational costs per

customer the average retail market operator must bear. In [22, 23 and 24], some typical



values are presented for the UK, European and Australian markets in the last decade.

The values found are based on benchmark costs for electricity retailers, so they can be

incorporated into regulated tariffs ensuring the provision of appropriate incentives for

retailers to operate efficiently.

As operating costs are a significant component of suppliers’ cost base, the estimation of

the appropriate level for these costs is a key part of the required assessment to set

default tariffs [22].

From [22], the definition pf the typical operating costs as supplier’s own costs of retailing

electricity exclude the costs of purchasing the electricity, the costs of meeting

environmental and social obligations and all the network charges. Focusing exclusively

the costs related to customer contact, billing and payment, metering, sales and

marketing, central overhead – IT and HR –, depreciation and amortisation, we may

extrapolate the costs of engaging a single customer of any type within the electricity retail

business.

In [22], an average OPEX per customer of 86 € is presented for the UK retailers

assessed.

Since electricity retail is considered a low margin activity – around 3% –, with one-third

of retailers in the most competitive markets – like UK and Netherlands – failing to

generate profit in the household segment, controlling the costs to acquire and serve

costumers is much relevant, particularly when competition and customers’ expectations

rise [23].

For the European multi-client retail utilities, three costs are considered as drivers for the

general profitability of the energy provision business, the marketing costs, the costs to

acquire and the costs to serve the costumers [23].

In [23], an average OPEX per customer of 68 € is presented – costs to acquire plus costs

to serve –, for the 39 European retailers assessed, grouped based on their competitive

environment and number of customers.

In [24], for each retailer, the number of customers accessing regulated tariffs, the energy

sales by tariff and customer category, the operating and depreciation expenses, an

estimation of the fixed and variable proportions of the operation and maintenance

expenses and the revenues arising from sales to regulated retail customers where

considered.

The default tariffs are to include an appropriate allowance for retail costs as well as a net

profit margin. The retail cost component of the default tariff is intended to compensate

retailers for customer service costs, such as operation and customer relations, billing

and revenue collection costs, some financial costs, marketing and advertising costs, IT

systems, costs associated with full retail competition, depreciations and regulatory

compliances [24].



In [24], an average OPEX per customer of 40 € is presented for the Australian retailers

assessed.

In Portugal, where DOMINOES LEFM is implemented at the local community level within

a distribution grid environment, for EDP, the integrated utility leading the electricity retail

market, the last two annual financial performance reports available, from 2017 and 2018

– [25 and 26] – present an average OPEX per customer of 32 € – considering supplies,

external services and personnel costs, and based on the number of active supplying

contracts.

However, the total OPEX per customer presented is related to the energy supply

business, and only a part of this valued must be considered for the engagement of

flexible consumers and prosumers through a LEFM, since some of the operational costs

are supported by the intermediary managing the LM actions, e.g., the ECSP. From the

models presented in [1] we might conclude that same of the costs normally included into

the energy provider OPEX, such as the costs with supplies and other required external

services, in the LEFM context are actually associated to actions performed by the LM

manager, thus not impacting directly in the retailer costs and margins.

Thus, since the energy provider is not handling the local energy/flexibility providers

engagement and management, required forecasts, marching, clearing, settlement and

billing, a cost decrease of about 40% will be assumed for the average OPEX per

customer each year.

Revenues

• Revenues from optimising the participation in the wholesale market;

𝑅1𝑛[€] = 𝐶1𝑛[€] − 𝐶2𝑛 [€]

Where,

R1n is the annual revenue, in year n, from optimising the participation in the wholesale

market through the LEFM, measured in €.

C1n is the annual cost, in year n, with day-ahead wholesale energy purchase without

optimising the portfolio through the LEFM, measured in €.

C2n is the annual cost, in year n, with day-ahead wholesale energy purchase after

optimising the portfolio through the LEFM and with the day-ahead LEFM energy

purchase, required to optimise the portfolio, measured in €.

𝐶1𝑛[€] = 𝐸𝑛𝑒𝑟𝑔𝑦 𝑊𝑆_𝑑𝑎𝑦−𝑎ℎ𝑒𝑎𝑑𝑛[𝑀𝑊ℎ] × 𝑃𝑟𝑖𝑐𝑒 𝑊𝑆_𝑑𝑎𝑦−𝑎ℎ𝑒𝑎𝑑𝑛

[€/𝑀𝑊ℎ]

Where,



Energy WS_day-ahead, n is the total Wholesale day-ahead energy to purchase in year n,

measured in MWh.

Price WS_day-ahead, n is the average price for Wholesale day-ahead energy in year n,

measured in €/MWh.

𝐶2𝑛[€] = (𝐸𝑛𝑒𝑟𝑔𝑦 𝑊𝑆_𝑑𝑎𝑦−𝑎ℎ𝑒𝑎𝑑𝑛[𝑀𝑊ℎ] − 𝐸𝑛𝑒𝑟𝑔𝑦 𝐿𝐸𝐹𝑀_𝑑𝑎𝑦−𝑎ℎ𝑒𝑎𝑑𝑛

[𝑀𝑊ℎ])

× 𝑃𝑟𝑖𝑐𝑒 𝑊𝑆_𝑑𝑎𝑦−𝑎ℎ𝑒𝑎𝑑𝑛[€/𝑀𝑊ℎ]

+ (𝐸𝑛𝑒𝑟𝑔𝑦 𝐿𝐸𝐹𝑀_𝑑𝑎𝑦−𝑎ℎ𝑒𝑎𝑑𝑛[𝑀𝑊ℎ] × 𝑃𝑟𝑖𝑐𝑒 𝐿𝐸𝐹𝑀_𝑑𝑎𝑦−𝑎ℎ𝑒𝑎𝑑𝑛

[€/𝑀𝑊ℎ])

Where,

Energy LEFM_day-ahead, n is the total LEFM day-ahead energy available in year n, measured

in MWh.

Price LEFM_day-ahead, n is the average price for LEFM day-ahead energy in year n, measured

in €/MWh.

• Revenues from minimising costs due to imbalances solving;

𝑅2𝑛[€] = 𝐶3𝑛[€] − 𝐶4𝑛 [€]

Where,

R2n is the annual revenue, in year n, from minimising costs due to imbalances solving

through the LEFM, measured in €.

C3n is the annual cost, in year n, with intraday wholesale energy purchase for imbalance

solving without previously minimising deviations through the LEFM, measured in €.

C4n is the annual cost, in year n, with intraday wholesale energy purchase for imbalance

solving after minimising deviations through the LEFM and with the intraday LEFM energy

purchase, required to minimise the deviations, measured in €.

𝐶3𝑛[€] = 𝐸𝑛𝑒𝑟𝑔𝑦 𝑊𝑆_𝑖𝑛𝑡𝑟𝑎𝑑𝑎𝑦𝑛[𝑀𝑊ℎ] × 𝑃𝑟𝑖𝑐𝑒 𝑊𝑆_𝑖𝑛𝑡𝑟𝑎𝑑𝑎𝑦𝑛

[€/𝑀𝑊ℎ]

Where,

Energy WS_intraday, n is the total Wholesale intraday energy to purchase in year n, measured

in MWh.

Price WS_intraday, n is the average price for Wholesale intraday energy in year n, measured

in €/MWh.

𝐶4𝑛[€] = (𝐸𝑛𝑒𝑟𝑔𝑦 𝑊𝑆_𝑖𝑛𝑡𝑟𝑎𝑑𝑎𝑦𝑛[𝑀𝑊ℎ] − 𝐸𝑛𝑒𝑟𝑔𝑦 𝐿𝐸𝐹𝑀_𝑖𝑛𝑡𝑟𝑎𝑑𝑎𝑦𝑛

[𝑀𝑊ℎ])

× 𝑃𝑟𝑖𝑐𝑒 𝑊𝑆_𝑖𝑛𝑡𝑟𝑎𝑑𝑎𝑦𝑛[€/𝑀𝑊ℎ]

+ (𝐸𝑛𝑒𝑟𝑔𝑦 𝐿𝐸𝐹𝑀_𝑖𝑛𝑡𝑟𝑎𝑑𝑎𝑦𝑛[𝑀𝑊ℎ] × 𝑃𝑟𝑖𝑐𝑒 𝐿𝐸𝐹𝑀_𝑖𝑛𝑡𝑟𝑎𝑑𝑎𝑦𝑛

[€/𝑀𝑊ℎ])



Where,

Energy LEFM_intraday, n is the total LEFM intraday energy available in year n, measured in

MWh.

Price LEFM_intraday, n is the average price for LEFM intraday energy in year n, measured in

€/MWh.

Research on revenues’ monetisation

The following research aims to explain the rational for the monetisation of the revenues

presented above, based on the required assumptions and considerations to find the

value more suitable to the proposed CBA.

Regarding the total wholesale day-ahead and intraday energy to purchase in year n,

measured in MWh – Energy WS_day-ahead, n and Energy WS_intraday, n –, and according to [27],

in Portugal, between 2008 and 2017, the average annual electricity consumption per

domestic consumer is 2407 kWh.

Regarding the average price for wholesale day-ahead and intraday energy in year n,

measured in €/MWh – Price WS_day-ahead, n and Price WS_intraday, n –, and according to [28 and

29], for Portugal, between 2007 and 2019, the arithmetic average price is 48 €/MWh.

Additionally, the total wholesale energy to purchase each year implies incurring in

additional costs from the retailer’s perspective, associated with the access to the

networks and with the overall system management.

Normally, the energy provider charges these costs to the consumer through the tariff.

Within the present CBA context, the proposed scenario proposed for retailer’s value

considers that all the energy/flexibility mobilised at the LM will be used to supply

consumers within the community and to solve local imbalances.

Thus, and according to [30], for the LV consumers with less than 20,7 kVA of contracted

power, a price increase of about 19% must be considered for the average price of

wholesale day-ahead and intraday energy each year, which implies network access and

the global use of the system to transport and distribute the energy bought at the spot

market.

Regarding the total LEFM day-ahead and intraday energy available in year n, measured

in MWh – Energy LEFM_day-ahead, n and Energy LEFM_intraday, n –, and considering the context

of the distribution grid environment assessed, for the total 200 consumers engaged in

the LM, with a 20% penetration of flexible consumers and prosumers – all the prosumers

are also flexible consumers and vice-versa, equiped with PV systems, residential storage

and flexibile loads – is considered that the typical flexible consumer and prosumer

presents a 1,5 kWp power available from flexible loads per day, a 3,5 kWp installed PV

capacity and a 5 kWh storage system. Each flexible consumer and prosumer will



generate approximatly 6 MWh of energy/flexibility per year, being able to offer to the LM

60% of the total energy/flexibility generated, corresponding to the average annual

flexibility and energy excess. This value is an assumption and corresponds to the the

average surplus of energy available, considering the ratio between the average annual

electricity consumption per domestic consumer assumed – 2,4 MWh – and the average

annual energy/flexibility generated per flexible consumer and prosumer assumed – 6

MWh.

Regarding the average price for LEFM day-ahead and intraday energy in year n,

measured in €/MWh – Price LEFM_day-ahead, n and Price LEFM_intraday, n – for Portugal, between

2007 and 2019, the arithmetic average price is 43,5 €/MWh, considering the spot market

prices from [28] and according to the parcel, “OMIE n x 0,9”, from the following formula,

presented in [19]:

𝑅𝑆𝑃𝑈𝑆𝐶 𝑛[€] = 𝐸𝑠𝑢𝑝𝑝𝑙𝑖𝑒𝑑𝑛

[𝑀𝑊ℎ] × 𝑂𝑀𝐼𝐸𝑛[€/𝑀𝑊ℎ] × 0,9

Where,

R SPUSC, n is the remuneration for the electricity supplied in year n, measured in €.

E supplied, n is the energy supplied in year n, measured in MWh.

OMIE n is the value resulting from the arithmetic average of the closing prices for

Portugal of the OMIE, the Operator of the Iberian Energy Market, in year n, measured

€/MWh.


The needed investments considered, mainly related to the required OPEX to prequalify

the energy provider, engage and take part in the LEFM every year, will be partly financed

by bank loans, thus the associated financial costs must also be considered. The rest of

the operation will be financed through equity or investments.

Apart from the loan repayments that will need to be considered, interests and taxes may

also be listed as financial cost to bear within the context of this BM.

To assess the magnitude of the combined financial costs and their respective impact in

the proposed CBA, we can also evaluate the retailers’ average financial costs per

customer, following the same approach adopted to value the operational costs.

Performing a similar assessment to the one implemented for the evaluation of the

operational costs, in Portugal, where DOMINOES LEFM is implemented at the local

community level within a distribution grid environment, for EDP, the integrated utility

leading the electricity retail market, the last two annual financial performance reports

available, from 2017 and 2018 – [25 and 26] – present an average value for the Earnings

Before Interests, Taxes, Depreciation and Amortisations (EBITDA) per customer of 4 €

– based on the number of active supplying contracts. With the EBITDA per customer we



can measure the financial costs per customer if we consider the average weigh the

interests, taxes, depreciation and amortisations have in the EBITDA.

To asses this ratio we may weigh the net income against the EBITDA, thus finding a way

to discount the earnings and stick to the weighing the interests, taxes, depreciation and

amortisations have, estimating the financial costs.

From [25 and 26] we can only access the global net income, aggregating the results of

all the business units of the integrated utility, but considering all the results available for

the twelve quarters available – 2016, 2017 and 2018 – the average ratio is 67%.

• Financial costs associated;

𝐹𝐶 𝑝𝑒𝑟 𝑐𝑢𝑠𝑡𝑜𝑚𝑒𝑟 [€]

= 𝐸𝐵𝐼𝑇𝐷𝐴 𝑝𝑒𝑟 𝑐𝑢𝑠𝑡𝑜𝑚𝑒𝑟 [€] × (1 −𝐸𝑎𝑟𝑛𝑖𝑛𝑔𝑠 𝑜𝑟 𝑁𝑒𝑡 𝑖𝑛𝑐𝑜𝑚𝑒 [€]

𝑇𝑜𝑡𝑎𝑙 𝐸𝐵𝐼𝑇𝐷𝐴 [€]) [%]

Where,

FC per customer is the financial costs per customer, measured in €.

EBITDA per customer is the Earnings Before Interests, Taxes, Depreciation and

Amortisations per customer, measured in €.

The same approach as the one presented for the evaluation of the OPEX impact must

be followed for the financial costs.

Thus, since for the energy provider a local flexible consumer and prosumer does not

present the same implications in terms of costs than a typical electricity retail costumer,

a cost decrease of about 40% will be assumed for the average EBITDA per customer

each year.

A reference update rate of 0,289%, corresponding to the 12 months EURIBOR rate (daily

average of t-1 + spread), used in [31], should be considered to update and adjust the

costs of the electricity retail activity in the liberalised market in Portugal.


In Table 11 the key parameters considered are summarised. These parameters were

introduced in the previous section and are crucial to define the costs and revenues

consider under the CBA over BM5.

Table 11 – Key parameters considered in the CBA.

Parameters Values

Revenues related

Energy WS_day-ahead, n

Energy WS_intraday, n

481,4 MWh, year n



Price WS_day-ahead, n

Price WS_intraday, n

48,0 €/MWh, year n (+19%)

Energy LEFM_day-ahead, n

Energy LEFM_intraday, n

144,0 MWh, year n

Price LEFM_day-ahead, n

Price LEFM_intraday, n

43,5 €/MWh, year n

Costs related

OPEX per customer per year 32 € per customer (-40%)

Other relevant

Number of customers 200 (from the distribution grid environment)

Penetration of flexible consumers and prosumers 20%

Average energy consumption per year per consumer

2,407 MWh

Average energy/flexibility generated per year per flexible consumer and prosumer

6 MWh

(1,5 kWp flexible loads + 3,5 kWp PV systems + 5 kWh storage systems)

Percentage of generation made available to the market per year per flexible consumer and prosumer

60%

EBITDA per customer per year 4 € per customer (-40%)

1–(Earning / EBITDA) ratio 67%

Interest rate plus spread 0,289%

The CBA results presented are the outcomes from the assessment over the benefits for

the retailer when two main perspectives are compared, the costs from suppling a

community where a LEFM is implemented, against the costs from suppling the same

community when there is no LM, and all the energy required by the retailer’s portfolio

must be bought at the spot market.

The key parameters characterised value all the costs and revenues consider for this BM

and were used to perform the simulations to evaluate its profitability and sustainability

across 15 years, the considered time frame for the project’s CBA.

Using the exact parameters presented in Table 11, the CBA simulations reveal the

following results – Table 12.



Total Operational Revenues 29.419,20 €




Total Financial Costs 964,80 €


16.549,21 €

Based on the CBA results, the profitability and sustainability of this BM, particularly

addressing the energy provider’s perspective, is highlighted, considering the 16.549,21

€ expected NPV achievable from enrolling in a LEFM reaching 200 consumers, with a

20% penetration of flexible consumers and prosumers.

An additional reference must be introduced to enable a correct interpretation of the

presented results. From the energy provider perspective, the costs considered are

proportional to the number of flexible consumers and prosumers engaged, because the

rest of the 200 consumers must be considered as regular clients or possible clients for

the retailer’s services, or ultimately, as competitors for the same resources available at

the LEFM, if we consider P2P between end-users.

The LEFMs present a significant business opportunity for retailers, since the operational

revenues incurred represent an effective gain, since the benefits come directly from

optimising its operation in an almost business as usual context, once the two main

perspectives considered are focused on the day-by-day portfolio optimisation, i.e., the

day-ahead energy sourcing optimisation at the wholesale market through the LEFM, and

the intraday deviations minimisation by reducing the costs incurred to mitigate portfolio

imbalances.

Moreover, the influence that some of the key parameters have in the CBA outcomes is

assessed through a sensitivity analysis associated to the BM risk assessment.


The BM5 doesn’t have a direct impact on the GHG emissions. However, indirectly, if the

prices available at the LM remained competitive against the wholesale market prices, the

demand for services supported by decentralised renewable-based generation and

energy efficiency-based DR will rise, increasing community consumers and prosumers

motivation to invest in DER and RES and thus boost the GHG emissions reduction.

Ultimately, the retailer himself can leverage and value economically the decarbonisation

of its portfolio.





Figure 13 – Influence that the penetration of flexible consumers and prosumers and the

percentage of energy generated and flexibility avaialble to the LEFM have, considering the NPV

evolution.

Figure 14 – Influence that the annual average day-ahead and the intraday prices at the WM

and LEFM have, considering the NPV evolution.



Figure 15 – Influence that the annual average OPEX & Financial Costs per customer have,

considering the NPV evolution.

In the sequence of the evaluation of the BM profitability and sustainability, the solution

robustness to key parameters is now analysed.

Six key parameters, coupled in three categories, are considered to test the robustness

of the results achieved and presented in the profitability and sustainability analysis.

• Regarding the influence that the penetration of flexible consumers/prosumers

and the percentage of generated energy/flexibility made available to the LEFM

by these consumers/prosumers have, the following scenarios were assessed:

o For the penetration of flexible consumers/prosumers in the LEFM, a

significant decrease in the profitability follows if a decrease from 20% –

base case – to 1% is considered. This variation in the expected NPV is

justifiable, since the energy provider incurs in costs directly proportional

to the number of flexible consumers/prosumers engaged through the

LEFM. Anyway, even a drastic decrease in the penetration of flexible

consumers/prosumers always leads to a positive outcome, if the local

prices’ competitiveness is guaranteed.

o For the percentage of energy generated and flexibility available to be

traded and activated at the LEFM, the turning point is reached when the

percentage considered drops down to 25%. When less than 25% of the

generated energy/flexibility from the flexible consumers/prosumers is

offered to the LM the costs from engaging those flexible

consumers/prosumers surpass the achievable revenues by mobilising

their energy excess/flexibility.

• Concerning the influence that the prices for day-ahead and intraday at the

wholesale and LM have, the following scenarios were assessed:

o For the wholesale price, the considered variation shows that, if the

considered price increase of about 19%, due to the costs with network

access and global use of the system to transport and distribute the



energy, is reduced to 2%, the turning point is reached and the expected

NPV becomes negative. This happens when the costs from engaging the

flexible consumers/prosumers surpass the margin allowed by the

difference between the wholesale price, plus 2%, and the LM price. Due

to the variation in the network access and system’s global use costs, the

local prices’ competitiveness is not enough to ensure the desirable

profitability. Moreover, we can also conclude that, if the direct spot market

prices were considered, i.e., wholesale price, plus 0%, there will be no

profit, at least considering the flexible consumers/prosumers engaging

costs applied to the conducted analysis.

o For the LM price, the considered variation shows that a price increase of

18% leads to a turning point in the profitability. The expected NPV

becomes negative when, for the same engaging costs, the average LM

prices rise to 51,33 €/MWh – 43,5 €/MWh +18%. Considering the average

wholesale price applied, 57,12 €/MWh – 48 €/MWh +19% –, we may

conclude that, for these prices, only a difference bigger than 5,79 €/MWh

between the wholesale and the LM prices grants a sustainable

investment.

• Regarding the costs considered and their influence, the following scenario was

assessed:

o A significant increase in the OPEX and financial costs per customer is

required to reach the profitability turning point. The considered OPEX

value per customer for the base case is 19,20 € – 32 € -40% –, and the

financial costs per customer is 1,61 € – 4 € x(1-Earning/EBITDA) -40%.

To reach the turning point, a value of 45,44 € for the OPEX per customer

and a value of 3,81 € for the financial costs per customer must be

considered.


The main risks related to the BM5 are particularly related to business opportunity and

competitiveness, general market context and evolution, legislation and regulation issues.

The risks comprised within these categories are listed below.

• The entering barriers are significant, hindering the retailers’ engagement

process, e.g., if the prequalification or other operational costs are too heavy,

considering the possible revenues;

• In one hand, the competitiveness within the LEFM can affect this BM, since the

energy providers are not the only stakeholders that can benefit from more

affordable prices in the LM. If a given market regularly presents attractive prices,

other market players will also be highly interested in accessing the offers, biding

for and activating the available resources, excluding the retailers from the game,



since these stakeholders are competing for the same resource but not

necessarily against the same reference price, due to the different nature of their

operational activity;

• In the other hand, the retailers’ interest in the LEFM can also be affected by the

general evolution of the market prices. Not only the LEFM market prices can

increase and stop being enough competitive against the spot market prices, or

instead, the spot market prices can decrease significantly in the years to come,

taking advantage of the scale to push for a cost’s reduction not accessible in the

LEFM smaller scale context;

• The legislation and the regulatory framework surrounding the implementation of

LEFM is still under development in most countries, decreasing the short-term

impact of a BM focused on this context.


Considering the abovementioned risks, the potential prevention measures are described

below.

In a rollout scenario, the legislation and regulatory framework evolution must accelerate,

because the required OPEX per MWh of energy/flexibility mobilised at the LEFMs will

tend to decrease with the increase in supply at the LMs.

• To tackle the regulatory risks, the legislation and regulation development must

be carefully monitored, to continuously assess the evolution of the potential

barriers and of the available opportunities.

Regarding the other risks identified, more related to the business nature and with the

general market competitiveness, extensive CBAs should be considered, using relevant

and reliable data, prior to the BM implementation, to properly estimate the possible gains

but also the most prominent impacts.

• To tackle the more business-oriented risks, the market conditions evolution

should also be monitored, considering the LEFM potential in the retailer’s periodic

SWAT analysis and, as stated, consider extensive CBAs over the specific BM to

implement.


The results from the CBA and sensitivity analysis performed over BM5 highlight the

general profitability of the investment in the perspective of the retailer.

However, the sustainability of the investment deeply depends on a comprehensive

assessment over the fundamental revenue sources and most relevant costs to consider.

The sensitivity analysis presented shows that a particular set of key parameters must be



extensively researched and tested to evaluate the robustness of the solution provided

by the CBA.

The interest that the energy provider may have in a LM, e.g., due to its local portfolio

and/or the imbalances normally associated, should always be accounted, and contrasted

with the typical penetration of flexible consumers/prosumers and the percentage of

generated energy/flexibility made available locally. Other factors to consider are related

with the LEFM context, such as the local prices available, whose competitiveness against

spot prices must continuously be assessed, and the costs incurred to be engaged in and

act.



3.6 Energy service provider in enabling / assistive role for local markets and providing ECSP capability for retailers, communities or other service providers



6

Energy service provider in enabling / assistive role for local markets and providing ECSP capability for retailers, communities or other service providers

Local energy market data hub manager and technical validator of market transactions

BM6 defines a business case where energy service provider is in enabling role for LMs

and provides ECSP capability for retailers, communities or other service providers. This

BM is described in detail in D5.1 and the associated UC – local energy market data hub

manager and TV of market transactions in D1.3.


Based in D5.1 BM consists of an energy service provider who provides ECSP capability

for retailers, communities or other service providers. End-users have more and more

own generation and storages. Energy service provider could facilitate to managing a

community of end-users and facilitate them to participate in the market and providing

flexibility. Also, local sharing and trading could be possible via energy service provider.

Additionally, ITC infrastructure and expertise in information services for

retailers/aggregators/DSOs/third parties to manage the LM could be provided.

The service provider will need strong ICT capabilities for local sharing of energy

management. Service provider could manage also grid costs and taxes. ICT systems will

need also interfaces to aggregated customers, retailers, communities, wholesale

markets and telecommunication system. Distributed resources at the customer site will

need appliances, remote-metering and remote-control infrastructure.

ECSP has connections to variety of different stakeholders:

• Parties responsible for metering or Datahubs to get end-users’/community

members’ consumption and production data;

• Retailers/aggregators/DSOs/TSOs to offer them flexibility services provided by

energy communities;

• Wholesale market operators to enable communities’ wholesale market

participation;

• Prosumers and consumers who want to engage in local sharing or trading;



• Appliance/generation/storage/control technology providers to provide necessary

technologies for end-users.


The main responsible for the BM is ECSP.

Empower and VPS will be responsible for the ICT services in the demonstrations in the

DOMINOES project.


The scope of BM6 is mainly local, since the consumers and prosumers are providers of

flexibility and energy. Whereas DSO, TSO, BRP, retailers and aggregators are

customers who could purchase the flexibility for grid management or portfolio

optimisation. Thus, BM6 has also connection to national (regional) energy market. In

addition, communities could purchase IT services to community management.

The actions and benefits for different stakeholders are described in the table below.

Table 13 – Stakrholders identification and benefit evaluation.

STAKEHOLDERS ROLE ACTION BENEFIT

DSO, TSO Customer Flexibility purchase Aggregated flexibility that

can be purchased for

grid/system management

BRP Customer Flexibility purchase A tool to manage

flexibility for portfolio

optimisation

RETAILERS,

AGGREGATORS

Customer Flexibility purchase A tool to manage

flexibility for portfolio

optimisation

WHOLESALE AND LOCAL

MARKETS

Opportunity to manage

local assets and

aggregate them for

wholesale market.

PRODUCERS/PROSUMERS Provider Energy provision Revenues from selling

(surplus) energy



COMMUNITIES Customer Purchase of IT services Opportunity to buy

community management

services

CONSUMERS Provider (of flexibility) Flexibility provision Lower energy costs from

retailer using the

flexibility, revenues from

selling flexibility

Main stakeholders of the BM are described in the Figure 16 – reported in D5.1. Energy

service provider could manage an energy community, facilitate local sharing and trading

of flexibility services and provide ICT platforms / services.

Energy community




Energy service

provider

ICT platform / servicesWS and LM(Day-ahead,

Intraday, Balancing)

Market representation

BRPDSO

Manage of the community

ICT platform / services

Figure 16 – BM stakeholders and relations – reported in D5.1.

BM6 have agreements that are presented in Table 14. C1 is an agreement between the

energy service provider and the end-user for participating in the LM. C2 and C3 include

agreements between the energy service provider and the wholesale market operator for

taking part in the wholesale / ancillary services markets. An agreement between the

energy service provider and the stakeholder is described in C4 where the stakeholder

utilises the ICT infrastructure. Contracts are described more in detail in D5.1.



Table 14 – Contracts for BM6.

C1 C2 C3 C4

Stakeholders

Energy service provider ✓ ✓ ✓ ✓

End-user/Prosumer ✓

DSO/retailer/aggregator/third party ✓

Wholesale market operator ✓

System operator ✓

BRP ✓ ✓

Type Dynamic ✓ ✓

Static ✓ ✓

Payment Type

Daily ✓

Monthly ✓ ✓ ✓ ✓

Annual ✓ ✓

Pricing

Action Base ✓

Static ✓ ✓ ✓

Incentives

Dynamic ✓

Shared savings/earnings ✓


BM6 defines a service provided by an energy service provider that could:

1) Manage a community of consumers/prosumers and represent them as a single

entity towards the wholesale markets;

2) Facilitate local sharing and trading of flexibility services for BRPs, DSOs and

TSOs;

3) Provide the necessary ICT infrastructure and expertise for

retailers/aggregators/DSOs/third parties to manage the LM.

End-users are increasingly turning into prosumers with their own generation, controllable

loads, and storages. However, they may not have the skills or interest to optimise the

use of these assets especially if there is a need for community-level optimisation.

Energy service provider could manage a community of consumers/prosumers and

represent them as a single entity towards the wholesale markets. It could facilitate local

sharing and trading. Flexibility services could be provided for BRPs, DSOs and TSOs.

In addition, an energy service provider could provide the necessary ICT infrastructure

and expertise in information services for retailers/aggregators/DSOs/third parties to

manage the LM.






Several stakeholders in the power system could benefit from the flexibility of end-users.

However, control technologies and software to manage flexibility are not necessarily

among the core competencies of retailers and DSOs.

Some retailers are already purchasing DR management services/platforms from

technology and software providers. However, some retailers and aggregators are also

developing their control platforms in-house.

Although the most innovative retailers and DSOs are considering the use of flexibility of

their customers, there is a lack of services directed to consumers/prosumers with the

aim of reducing their dependence on the traditional power system players and promoting

local generation.


The need for flexibility management services will increase in the future. This is due to

e.g. the forecasted increase of intermittent renewable generation and the requirement to

use 15 minutes as the imbalance settlement (set in the Commission regulation (EU)

2017/2195 [32]). Whether the management services and platforms are developed in-

house by energy companies or bought as a service (or needed at all) depend on multiple

factors. These include, for example, the availability and price of platform services in the

market, size of the retailer/DSO/aggregator, and inclusion of flexibility use in retailers’

and DSOs’ strategy. Furthermore, the service defined is closely related to the other BMs

defined in DOMINOES and they require ICT and control capabilities which this BM

provides.

In addition to the increased need for flexibility management, services for communities

will become more relevant due to the new EU legislation and increasing proportion of

small-scale generation installed by prosumers, as mentioned under BM4.


For DSOs, retailers and aggregators the alternative for outsourcing the flexibility

management platform is to develop it in-house which will require personnel with IT skills.

For communities, the IT development is unlikely to be feasible.

Thus, the options are:

• Baseline: no communities;



• Community management services are developed in-house by retailer,

aggregator, or DSO;

• Community IT services are bought from the ECSP.

Another option is that the ECSP instead of service provision, sells the software to the

retailer or community.


The BM has no physical impacts on soil, water and air, and no biological impacts on

flora, fauna and ecosystems.

The impact on global electrical system can be the increase in the overall system

efficiency and the impact on households can be energy savings and new revenue

streams.

For the climate change perspective, the BM has an indirect impact on climate change

because of:

• More incentives to install renewable generation → less fossil based power

generation;

• More efficient use of resources and energy;

• Increasing the market liquidity in the provision of ancillary services and smoothing

of electricity demand curve → less use for peak power plants.

These all will have an impact on GHG emissions. It’s very hard to quantify the impact.



In this BM, an energy service provider manages a community of local consumers and

prosumers and facilitates sharing and trading of flexibility services also for other

stakeholders’ (e.g. TSO, DSO) needs. In addition, the ICT platform used to manage

communities may be offered as a separate service for retailers or other stakeholders

willing to act as CMs. As in the latter case there may occur various needs to adjust

components of the platform, causing very different costs, this CBA focuses only on the

first case.


The investment cost included in this analysis is the estimated cost of developing the ICT

platform enabling ECSP activities. This is a novel service and is not expected to replace

any existing systems. Thus, the replacement costs and residual value are not

considered.




The main operating costs are the wages of the personnel operating the ICT platform.

Revenues include subscription fees from the community members and share of the

flexibility services sold to the external markets.


Possible sources of financing for ECSP in BM6 are public contribution (in the

development phase), own capital and different loans.


The table summarise the total cost and revenues, which were introduced in the previous

section and the expected NPV. The considered time frame for the project is 15 years


Table 15 – Total costs & revenues and ENPV.



Total Operational Revenues 600.000,00 €



Total Financial Costs 70.000,00 €


55.643,77 €

Based on the results, the expected NPV is 55.643,77 €. Thus, the positive NPV indicates

that the BM6 is profitable with the cost and revenue assumptions. The BM risk

assessment associate with the uncertainties of the BM.


The service proposed in this BM is mainly IT-based, and the impact on the GHG

emissions depends on the assets and motives of the community members or the

stakeholder purchasing the ICT platform service. Nevertheless, the BM is likely to

contribute to GHG reduction as the BM also encourages matching of local demand and

supply, thus reducing losses in transmission and distribution. Furthermore, if the

community members decide to install more renewable generation due to the availability

of the service and the generation it possibly replaces has higher emissions, the BM may

reduce further GHG emissions.





The analysis of the cost and benefits is done for a generic example in BM6, so the

number of community members and the market price have a considerable impact on the

revenues.

Varying factors or uncertainties that affect the financial analysis of the proposed BM:

• Regulative environment that would support BM is now lacking and thus the

demand for the BM is uncertain

• This BM could be offer to various customers, is there potential in all or some of

them, how much customization different customer groups require regarding the

investment and operational costs

• Pricing model: based on fixed fee and/or based on sharing on the market profits

o If based on market profits: level of market prices in the future when on the

other hand, there is more need for the flexibility resources but on the

hand, more resources and service providers on providing the flexibility

• Investment costs are difficult to estimate since the technical requirements are not

defined and for the market operator connections are defined by the

o Number of interaction interfaces to market places is uncertain

• Scalability and replicability of the solution, solution should require as little as

possible customization, possible varying requirements:

o different market operators and countries

o Different types of LMs or energy communities


Consumers and prosumers are providers of flexibility/energy in BM6, so engagement of

the customers in the LMs and energy community, including acceptance for sharing data

and the DR actions is required.

Technical requirements and acceptance of aggregated resources to provide ancillary

services (TSO) or balancing services (BRP) if the requirements are favouring generation

units or the requirement are becoming stricter like demanding more real-time information

about the resource should consider. There is also a risk of competition from other service

providers.

Financial risks related to BM6 are level of market prices in the future and sharing the

profits on provision of the services for DSO, TSO, BRPs to the community and LM

participants.

Technology and telecommunication risks related on the technical performance of the

system and IT risks are involved in BM6. In addition, the information exchange



requirements can be also different in different countries, which can add scalability

challenges.

Now some the legislation or the market rules inhibits the participation of flexible loads. In

the long term, the risk related to market access of flexible loads is likely to become

irrelevant in EU member states due to the requirements of the recast electricity directive

2019/944 [7].

In many European countries centralised data management systems for electricity retail

markets (datahubs) are being established. Depending on the which extent the

information content from the electricity community is handled in the Datahub, the demand

for the energy community service provision might be smaller.


Risks related to the engagement of the customers can be mitigated with clear

communication and long enough contracts. Also, the benefit to the customer should be

clear. Communication should be also clear between all participants, so that all are aware

of principle of the BM6.

The energy service provider should be aware of market development and be able to

adjust to the latest market requirements. Also, communication with regulators and

legislators on the benefits and barriers are important.


This chapter described a BM where energy service provider is in an enabling role for

LMs and provides ECSP capability for retailers, communities or other service providers.

This BM requires that the legislative environment will be favourable for the new flexibility

resources to participate the markets.

According to the assumptions and financial analysis this BM is feasible with relatively

low margin. Thus, special attention should be paid on the scalability of the solution for

multiple markets to extent the revenue base with minimal additional operational costs.

Also, the risks related on the revenues from sharing of the financial benefits with the

customer are significant and BM should focus more on fixed subscription fees, if

possible. Due to high uncertainty of multiple factors related on the performance of the

BM6, sensitivity analysis for this BM was not viable and risks are described more in

qualitative way.

CONCLUSIONS


4 Conclusions

D5.3. presents a comprehensive CBA over the BMs proposed for the DOMINOES LEFM

concept.

The feasibility of BM1, that considers a VPP manager aggregating DER and offering

flexibility to markets, is dependent on the end-user willingness to participate and on

sharing of the market benefits between asset managers and providers.

The CBA performed shows that, according to the assumptions made, the BM seems to

be feasible. However there some uncertainties to consider, mostly related to regulatory

obstacles, investment costs and risks related to future market prices affecting the

achievable benefits.

For BM2 and 3, a significant abstraction is required to estimate financial costs and

revenues that the DSO, due to the regulated nature of its activity, publicly auditable, is

not capable or allowed to extrapolate without a public consultation of a national regulation

framework that generates consensual values for OPEX, CAPEX and system benefits.

Thus, a qualitative analysis over the use of transactive energy and the implementation

of LEFM for flexibility aggregation and system services provision was presented.

A step-by-step implementation of LEFM for DSO benefit was evaluated, focusing the

impacts, required demand conditions, financial challenges, economic opportunities,

perceived system benefits and potential regulatory options for the DSO´s OPEX and

CAPEX solutions. The available options to address distributed vs centralised technical

validation of such market actions are not consensual and are still under a broad

discussion at local and European level by NRAs, TSOs and DSOs.

Regarding BM4, its context and feasibility were analysed with a focus on the potential

added value for the community. The role of an energy management company acting as

a CM, enabling the engagement and the sharing of excess generation within the

community is considered. Such role is new in the energy sector and it depends on an

enabling regulatory and legislative framework which is still under development in many

countries.

With the costs and revenues assumed and used in the analysis, the BM seems feasible.

However, the implementation relies on outsourced ICT and forecast services and thus

their availability and costs impact the profitability of the BM. Furthermore, changes in the

community members after the initial investment can have large impact on the profitability

as well.

The retailer or energy provider’s perspective is considered within the scope of the CBA

over the BM5.

CONCLUSIONS


The profitability and sustainability of the considered investment relies on the assertive

assessment over the possible revenues and costs to consider, and the presented

sensitivity analysis shows how a set of key parameters may affect the robustness of the

solution provided by the CBA.

The penetration of flexible consumers/prosumers and the percentage of generated

energy/flexibility made available locally, and accessible through the LEFM, the local

prices available, whose competitiveness against spot prices must continuously be

assessed, and the costs incurred to be engaged in and act at the LM are some of the

parameters targeted by the sensitivity analysis performed.

BM6 considers a scenario where energy service providers play an enabling role for LMs

and provides ECSP capability for retailers, communities or other service providers. The

evaluated BM requires a favourable legislative context, enabling flexibility resources to

take part in the marketplace as dispatchable assets.

According to the assumptions considered the financial analysis performed shows that

the BM is feasible but presents a relatively low margin. A special attention should be paid

on the scalability of the solution for multiple markets to extent the revenue base with the

minimal addition of operational costs. Moreover, the risks associated to source of

revenues from sharing of the financial benefits with the customer are not neglectable.

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