dominoes deliverable d5.3 cost benefit analysis of the...
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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
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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.
D5.3_Cost Benefit Analysis of the Business Models Page 3 of 92
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
D5.3_Cost Benefit Analysis of the Business Models Page 4 of 92
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.
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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
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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
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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.
DOMINOES GENERAL OBJECTIVES AND CONTEXT
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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 GENERAL OBJECTIVES AND CONTEXT
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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
DOMINOES GENERAL OBJECTIVES AND CONTEXT
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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.
DOMINOES GENERAL OBJECTIVES AND CONTEXT
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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.
DOMINOES GENERAL OBJECTIVES AND CONTEXT
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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.
DOMINOES GENERAL OBJECTIVES AND CONTEXT
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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.
DOMINOES GENERAL OBJECTIVES AND CONTEXT
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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.”
DOMINOES GENERAL OBJECTIVES AND CONTEXT
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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
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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
CBA OF THE BUSINESS MODELS
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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
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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.
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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.
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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
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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.
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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
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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.
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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.
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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.
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• 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.
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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.
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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.
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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.
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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.
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3.2 Aggregator flexibility provision to DSO for network management
3.2.1 BM02 project identification
Project Business Models Use cases
2
Aggregator flexibility provision to DSO for network management
Local market flexibility and energy distributed resources for optimal grid management
3.2.1.1 Physical elements and activities
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.
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• 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.
3.2.1.2 The body responsible for BM project implementation
EDPD will be the responsible party for the BM project study potential implementation.
3.2.1.3 BM project impact on stakeholders
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.
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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.
3.2.2 BM02 objectives
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.
3.2.3 BM02 technical feasibility & environmental sustainability
3.2.3.1 Demand analysis
3.2.3.1.1 Current demand
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
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initiatives can be useful to incentivize the market to start offering flexibility for distribution
purpose.
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. 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.
3.2.3.1.2 Future demand
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.
3.2.3.2 Option analysis
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.
3.2.3.3 Environment and climate change considerations
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.
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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 Location and technical design
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
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.
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3.2.4 BM02 financial analysis
3.2.4.1 Introduction
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.
3.2.4.2 Investment cost, replacement costs and residual value
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.
3.2.4.3 Operating costs and revenues
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.
3.2.4.4 Sources of financing
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
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maintenance costs accepted by the NRA. However, the ownership of a flexibility platform
will have a significant influence on the way it is financed.
3.2.4.5 Financial profitability and sustainability
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.
3.2.4.6 Evaluation of GHG externalities
Flexibility offers shall internalize the impact of GHG on the costs of either procuring
flexibility or choosing to adopt conventional investment options.
3.2.5 BM02 risk assessment
3.2.5.1 Sensitivity analysis
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.
3.2.5.2 Qualitative risk analysis
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.
3.2.5.3 Risk prevention and mitigation
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.
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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.
3.2.6 BM02 conclusions
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.
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3.3 Using transactive energy for network congestion management
3.3.1 BM03 project identification
Project Business Models Use cases
3
Using transactive energy for network congestion management
Local market flexibility and energy distributed resources for optimal grid management
3.3.1.1 Physical elements and activities
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
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.
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;
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• 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.
3.3.1.2 The body responsible for BM project implementation
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.
3.3.1.3 BM project impact on stakeholders
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.
3.3.2 BM03 objectives
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.
3.3.3 BM03 technical feasibility & environmental sustainability
3.3.3.1 Demand analysis
3.3.3.1.1 Current demand
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.
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. In 2019
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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.
3.3.3.1.2 Future demand
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.
3.3.3.2 Option analysis
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
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(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.
3.3.3.3 Environment and climate change considerations
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.
3.3.4 BM03 financial analysis
3.3.4.1 Introduction
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.
3.3.4.2 Investment cost, replacement costs and residual value
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.
3.3.4.3 Operating costs and revenues
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.
3.3.4.4 Sources of financing
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
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its investment recognised and rewarded with the regulatory rate of return and have
service procurement costs accepted by the NRA.
3.3.4.5 Financial profitability and sustainability
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.
3.3.4.6 Evaluation of GHG externalities
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.
3.3.5 BM03 risk assessment
3.3.5.1 Sensitivity analysis
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.
3.3.5.2 Qualitative risk analysis
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.
3.3.5.3 Risk prevention and mitigation
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
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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.
3.3.6 BM03 conclusions
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.
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3.4 Sharing the exceeding PV generation in the scope of energy communities
3.4.1 BM04 project identification
Project Business Models Use cases
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
3.4.1.1 Physical elements and activities
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.
3.4.1.2 The body responsible for BM project implementation
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.
3.4.1.3 BM project impact on stakeholders
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.
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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.
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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 ✓
3.4.2 BM04 objectives
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.
3.4.3 BM04 technical feasibility & environmental sustainability
3.4.3.1 Demand analysis
3.4.3.1.1 Current demand
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,
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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.
3.4.3.1.2 Future demand
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.
3.4.3.2 Option analysis
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).
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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.
3.4.3.3 Environment and climate change considerations
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.
3.4.3.4 Location and technical design
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.
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3.4.4 BM04 financial analysis
3.4.4.1 Introduction
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.
3.4.4.2 Investment cost, replacement costs and residual value
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.
3.4.4.3 Operating costs and revenues
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.
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3.4.4.4 Sources of financing
The needed investments are financed through bank loans (73%) and an investor (27%).
The financial revenues match the initial investment cost 780.000,00 €.
3.4.4.5 Financial profitability and sustainability
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
and 0,289% has been used as the discount rate.
Table 8 – Total cost & revenues and ENPV.
Costs & Revenues Values
Total Initial Investment 780.000,00 €
Total Operational Revenues 3.767.678,56 €
Total Operational Costs 2.046.618,71 €
Total Financial Revenues 780.000,00 €
Total Financial Costs 1.037.534,56 €
Expected NPV (sum of the updated cash flows)
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.
3.4.4.6 Evaluation of GHG externalities
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.
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3.4.5 BM04 risk assessment
3.4.5.1 Sensitivity analysis
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
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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
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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%
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3.4.5.2 Qualitative risk analysis
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.
3.4.5.3 Risk prevention and mitigation
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
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3.4.6 BM04 conclusions
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.
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3.5 Retailer as user of the local market
3.5.1 BM05 project identification
Project Business Models Use cases
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.
3.5.1.1 Physical elements and activities
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.
3.5.1.2 The body responsible for BM project implementation
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.
3.5.1.3 BM project impact on stakeholders
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
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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
CONSUMERCONSUMERCONSUMERCONSUMER
PROSUMERPROSUMERPROSUMERPROSUMER
PRODUCERPRODUCERPRODUCERPRODUCER
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
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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.
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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
3.5.2 BM05 objectives
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 BM05 technical feasibility & environmental sustainability
3.5.3.1 Demand analysis
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
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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;
3.5.3.2 Option analysis
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.
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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.
3.5.3.3 Environment and climate change considerations
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.
3.5.4 BM05 financial analysis
3.5.4.1 Introduction
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.
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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.
3.5.4.2 Investment cost, replacement costs and residual value
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.
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3.5.4.3 Operating costs and revenues
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.
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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
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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].
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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,
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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])
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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
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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.
3.5.4.4 Sources of financing
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
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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.
3.5.4.5 Financial profitability and sustainability
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
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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.
Table 12 – Total cost & revenues and ENPV.
Costs & Revenues Values
Total Operational Revenues 29.419,20 €
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Total Operational Costs 11.520,00 €
Total Financial Costs 964,80 €
Expected NPV (sum of the updated cash flows)
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.
3.5.4.6 Evaluation of GHG externalities
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.
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3.5.5 BM05 risk assessment
3.5.5.1 Sensitivity analysis
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.
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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
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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.
3.5.5.2 Qualitative risk analysis
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,
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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.
3.5.5.3 Risk prevention and mitigation
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.
3.5.6 BM05 conclusions
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
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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.
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3.6 Energy service provider in enabling / assistive role for local markets and providing ECSP capability for retailers, communities or other service providers
3.6.1 BM06 project identification
Project Business Models Use cases
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.
3.6.1.1 Physical elements and activities
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;
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• Appliance/generation/storage/control technology providers to provide necessary
technologies for end-users.
3.6.1.2 The body responsible for BM project implementation
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.
3.6.1.3 BM project impact on stakeholders
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
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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
CONSUMERCONSUMERCONSUMERCONSUMER
PROSUMERPROSUMERPROSUMERPROSUMER
PRODUCERPRODUCERPRODUCERPRODUCER
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.
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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 ✓
3.6.2 BM06 objectives
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.
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3.6.3 BM06 technical feasibility & environmental sustainability
3.6.3.1 Demand analysis
3.6.3.1.1 Current demand
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.
3.6.3.1.2 Future demand
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.
3.6.3.2 Option analysis
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;
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• 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.
3.6.3.3 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.
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.
3.6.4 BM06 financial analysis
3.6.4.1 Introduction
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.
3.6.4.2 Investment cost, replacement costs and residual value
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.
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3.6.4.3 Operating costs and revenues
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.
3.6.4.4 Sources of financing
Possible sources of financing for ECSP in BM6 are public contribution (in the
development phase), own capital and different loans.
3.6.4.5 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 15 – Total costs & revenues and ENPV.
Costs & Revenues Values
Total Initial Investment 110.000,00 €
Total Operational Revenues 600.000,00 €
Total Operational Costs 472.500,00 €
Total Financial Revenues 110.000,00 €
Total Financial Costs 70.000,00 €
Expected NPV (sum of the updated cash flows)
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.
3.6.4.6 Evaluation of GHG externalities
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.
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3.6.5 BM06 risk assessment
3.6.5.1 Sensitivity analysis
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
3.6.5.2 Qualitative risk analysis
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
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D5.3_Cost Benefit Analysis of the Business Models Page 87 of 92
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.
3.6.5.3 Risk prevention and mitigation
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.
3.6.6 BM06 conclusions
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
D5.3_Cost Benefit Analysis of the Business Models Page 88 of 92
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
D5.3_Cost Benefit Analysis of the Business Models Page 89 of 92
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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