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Regulatory and Policy Aspects for a Cellular Design
of Electricity Markets
Aiko Schinke-Nendza, Gerald Blumberg, Abuzar Khalid and Christoph Weber
House of Energy Markets and Finance (HEMF)
University of Duisburg-Essen
Essen, Germany
e-mail: aiko.schinke-nendza@uni-due.de
Abstract—Future energy systems are facing an increasing
number of mainly small-scale renewable energy sources (RES)
and sector-coupling units. This change poses technical and
market-related challenges in terms of consistent market and
system operation across sectors. The cellular approach (CA) is
considered a promising concept to overcome these challenges.
Since energy cells are communicating to interconnected
neighboring energy cells exclusively, the effort of data
processing can be reduced effectively. Beyond the design of an
appropriate electricity market structure, the question of
integrating this concept into the status quo of the regulatory
framework is a key issue. Therefore, this paper examines the
relevant aspects of the regulatory and policy framework with
regard to the integration of an electricity market design based
on energy cells. The degree of correspondence or conformity of
the proposed design with the key current European and
national regulations is assessed. Relevant regulatory aspects are
identified, and possible adoptions are discussed.
Keywords—Cellular approach, independent system operator,
market design, regulatory and policy framework
I. INTRODUCTION
To mitigate the effects of climate change, the
decarbonization of the energy sector is required, inducing
new challenges for future energy systems. For instance,
increased shares of variable renewable energy sources (RES)
are affecting the power grid, thus, raising the question of its
long-term optimal technical and economic structure with
regard to infrastructure expansions and operational
opportunities for an improved operation. These questions are
closely linked to future investments in system security and
operation of renewables, electricity storage, other power
plants and sector coupling technologies [1]. The design of
future electricity markets should enhance the coordination of
the overall energy system operation, involving the advantages
of sector-coupled networks, storages, demand, and supply,
while taking real-world information and communication
technology (ICT) limitations into account.
In this context, present electricity markets are already
facing two major challenges as consequences of the ongoing
decarbonization: decentralization and congestion
management (cf. also [2]). The decentralization of the
electricity sector implies an increasing number of small-scale
units, located in the lower voltage levels of the electricity
network. These decentralized units, e.g., photovoltaic power
plants and storages, heat pumps, electric vehicles etc., may
offer valuable contributions of flexibility to the electricity
markets, yet this is currently only partially usable. The
reasons for the partial usage of decentralized flexibility in
purely centralized electricity markets are linked to the present
market design. For traders, the integration of small-scale units
is only worthwhile if several of these plants are aggregated,
so that the resulting uncertainty can be significantly reduced
and cost advantages can be gained, due to the scale of
operation. In this context, the market clearing process, which
in most European member states is typically carried out based
on simplified network externalities [3], induces another
challenge: After carrying out the market clearing process,
resulting violations of technical constraints are leading to
congestions, whereby measures are typically postponed in the
temporal sequence. In this context, especially renewable
curtailment, redispatching and countertrading are the most
relevant measures taken in European electricity markets.
Instead of using flexibility to cope with local congestions,
renewable power plants are currently often curtailed while
conventional power plants are redispatched to serve the
missing electricity. Even if the decentralized units are
offering flexibility on the centralized electricity market, there
is no suitable mechanism so far to provide flexibility at the
local level, capable to face resulting limitations of the
information and communication technology (ICT) as well.
Another reason for the present challenges, related to the first
reason, are distorted price signals arising from the present
regulatory framework. Since, network externalities or
congestions are not reflected in price signals, the latter are not
incentivizing adequate operational and investment decisions.
This hinders especially sector-coupling technologies and
other flexibilities to become economically viable [4].
In this context the novel market design proposed by
Schinke-Nendza et al. [2] may provide a framework to unfold
the potential of integrating decentralized units while coping
with congestions appropriately. Hereby, the electricity
market is based on a two-layer market clearing process
incorporating network constraints, while introducing system
operators on a central and local level. In opposite to present
transmission and distribution system operators (TSOs &
DSOs), independent system operators (ISOs) are envisaged,
which would be responsible for operating the corresponding
network while organizing the market clearing based on a
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nodal pricing regime (thus, incorporating congestion
management during market clearing). Each of the central and
local ISOs takes into account the generation and demand units
as well as the networks constraints units in its own territory
and communicates only with interconnected entities (i.e.,
other ISOs or market participants). Thereupon, the market
clearing can be carried out iteratively, e.g., based on
distributed and parallel optimization, see [5]. Therefore, in
the novel market design the computational effort may be
reduced effectively for each entity, while enabling the
utilization of flexibility in electricity market.
This market design can be implemented as part of the
cellular approach (CA) leading to a cellular energy system
(CES), which is currently developed as part of the project
ZellNetz2050, cf. [6]. This project aims at developing a
cellular energy system for the year 2050, based on a
brownfield approach taking the present regulatory framework
into account. Subsequently, the concept a CES is therefore
subsequently introduced in a first step, including also the
intended market clearing process. Thereupon, the relevant
regulatory and policy aspects of the European framework are
analyzed and evaluated with regard to the market design in a
structured manner. Finally, the key findings regarding the
solution of the previously introduced issues are highlighted.
II. CELLULAR ENERGY SYSTEM
In the following, the CA is considered as the cross-
sectoral integrated energy system planning and operation [6,
7] and serves as a basis for a novel market design, cf. [2]. The
concept of the CES is based on hierarchically organized
energy cells applying the energetic subsidiarity principle,
thus, providing the possibility to handle the ICT limitations
of centralized electricity markets effectively [6].
A. Energy cells and cell levels
Each energy cell is defined as a spatially delimited1 part
of a multisector energy system and is operated by an energy
cell management (ECM) with a system operator (SO)
carrying out the market-based processes and a system
controller (SC) handling the technical processes.
1 Cf. [7] for the definition of the EC boundaries.
In this context, the CES is organized by three energy cell
levels (A to C), where all individual units, i.e., generation,
load and storages, providing different kinds of flexibility, are
comprised as the energy cells of Level A. These Level A
energy cells are operated by the unit operator (UO) and are
connected to different networks (electricity, gas and heat)
belonging to an energy cell of Level B or C. Thereupon, the
Level B energy cells cover areas corresponding to a given
electricity distribution system while the superimposed Level
C energy cells cover the transmission system. In addition, all
related heat and gas networks of the covered area belong to
the same energy cell of Level B or Level C.
The individual units of the Level A energy cells are
optimized by the UO according to an individual (corporate)
objective function of the incorporated units. Since the SOs of
the Level B and C energy cells include the network
infrastructure exclusively, they are comparable to an
independent system operator (ISO) in other market designs
[8]. Hence, the SO of Level B is named local ISO (LISO) and
the one of Level C is named central ISO (CISO).
B. Two-stage market design
The general structure of the electricity market design of
the CA proposed in [2] is depicted in Fig. 1. The focus is
thereby on the contractual relations, power flows as well as
the trading and coordination processes between the relevant
entities. The CES includes a hierarchical structure with
multiple unit managers and operators, several LISOs and one
central CISO. Similar to several ISOs covering different parts
of the US [8], several interconnected CISOs may be
envisaged within Europe, too. However, as mentioned
beforehand each LISO is exactly connected to one
superimposed CISO.
1) Market clearing and market segments
Besides the previously mentioned UO responsible for
operating units of energy cell Level A, this structure
introduces the unit manager (UM) serving as (electricity)
trader, i.e., the aggregator. Hence, UMs are taking over the
responsibilities of individual UOs, and act as traders to the
different submarkets of the electricity system. Therefore, UO
of an individual unit has the following duties: to purchase, sell
and buy energy, capacity, balancing services and ancillary
Fig. 1 Overview of the electricity market design with local ISOs and central ISO in the cellular approach. Note that ECs on level
A can also contain sector-coupling units or more than one unit, e.g., a load with an PV and a storage.
Virtual 5th International Hybrid Power Systems Workshop | 18 – 19 May 2021
services, as well as to report ex-post realized power flows for
the ISO to settle the energy balance.
Regarding energy cell Level B, several LISOs are
operating the corresponding distribution systems of the
electricity system, thus integrating the underlying energy
cells of Level A. Furthermore, the LISOs are integrated into
the overall market clearing process by transmitting
aggregated bids (including, e.g., exchange powers and
operational information) to the connected networks, i.e., to
the superposed CISO. In this context, the LISO is carrying
out a pre-market-clearing process taking local restrictions
into account to obtain the aggregated bids. Therefore,
underlying units of energy cell Level A are capable to
participate in submarkets procuring energy balancing and
ancillary services. Furthermore, with respect to the proposed
market design, LISOs are able to dissolve local congestions
and incorporate other network restrictions immediately.
On energy cell Level C, the CISO receives the aggregated
bids and performs the central market clearing and dispatching
process resulting in locational marginal prices (LMPs).
Therefore, the clearing of the energy market can be carried
out, incorporating a market-based procurement of balancing
and ancillary services simultaneously [5]. Hence, the
restrictions and requirements of the other submarkets are
taken into account by the CISO together with the system
operation. Regarding the market segments, the CISO
coordinates the spot markets and related submarkets required
for the secure system operation in his energy cells,
exclusively. The long-term, purely financially settled
derivative markets are overseen by a separate authority, thus
enabling UOs and UMs to trade power derivatives until one
day in advance to the physical delivery. Therefore,
appropriate hedging instruments can be incorporated while
ensuring a secure, competitive, flexible and non-
discriminatory system operation.
2) Governance structure of the ISOs
To ensure the competitive, transparent, and non-
discriminatory coordination of the ISOs, the governance
structure of all ISOs in the proposed market design should
follow the principle of independence. Hence, no market
participant or subgroup of participants of the market should
be able to control decisions, procedures and criteria of the
market and system operation [9]. This separation of the
market and system operating entity (i.e., the ISO) and the
asset owning entities (e.g., the network owners) is intended in
line with [10]. Hereby, the governance structure proposed by
Schinke-Nendza et al. [2] does not only ensure a transparent
and non-discriminatory competition.
III. REGULATORY AND POLICY ASPECTS
When developing a novel market design for the CA, the
key regulatory aspects in the present regulatory and policy
framework of electricity markets have to be reflected.
Focusing on the previously mentioned challenges, cf.
Section I, we address this for the case of Germany which is
integrated into the European framework of electricity
markets. In addition, the relevance to and the impact on the
proposed market design is evaluated subsequently for each
aspect.
A. Status quo of the regulatory framework
The corner stone for the liberalization of the electricity
sector in Europe has been laid in 1996 by directive 96/92/EC
concerning common rules for the internal market in electricity
[11]. Thereupon, the EU adopted various legislative packages
in 2003 and 2009, cf. [12, 13], to support the liberalization of
the energy market and to establish an internal market for
electricity. In terms of recent enactment, the so-called clean
energy package repealed the former regulatory framework
and introduced further steps towards an internal market in
electricity in 2019. As part of the clean energy package,
regulation 2019/943 on the internal market for electricity [14]
has been introduced as a binding legislative act, thus
applicable in its entirety in all member states while overruling
national laws. Furthermore, the common rules for the internal
market for electricity have been adopted as well by directive
2019/944 [15], setting objectives that all EU countries must
reach and translate into their national legislation by January
1st, 2021. In addition, the establishment of a EU agency for
the cooperation of energy regulators (ACER) with extended
competences has been addressed by Regulation 2019/942, see
[16]. Especially directive 2019/944 ensures an open
electricity market, based on the following principles:
− an open access to the electricity system for customers and
independent producers, respectively,
− the unbundling of vertically integrated system operators
− and the establishment of objective and non-
discriminatory criteria for the dispatching of power.
The beforehand mentioned process of liberalization in the
electricity sector in Europe has formed a zonal market
structure in the different member states, thus the internal
market in electricity consists of individually cleared bidding
zones. These zonal market clearings are coordinated through
an intra-zonal a cross-zonal capacity allocation process,
whereby the latter is carried out using the so-called Flow-
Based Market Coupling (FBMC). However, in these
processes of capacity allocation, typically simplified network
externalities are considered [3].
B. Electricity markets and market coupling
When considering electricity markets, directive 2019/944
clearly defines these as “markets for electricity, including
over-the-counter markets and electricity exchanges, markets
for the trading of energy, capacity, balancing and ancillary
services in all timeframes, including forward, day-ahead and
intraday markets” [14]. Furthermore, the directive requests
competitive, consumer-centered, flexible and non-
discriminatory electricity markets for all member states,
while extending the scope of application to the cross-border
trade of the internal market as well. The directive claims
transparency, proportionality and non-discrimination
regarding market rules, fees, and treatment in general.
Furthermore, these rules apply especially to the following
aspects [15]:
− access to wholesale markets and to data,
− balancing responsibility and switching processes,
− billing regimes and if applicable, licensing.
In addition, customers’ free choice of suppliers and
market-based supply prices, with minimized public
interventions, form another cornerstone of the organization of
electricity markets. Hereby, public interventions in the
Virtual 5th International Hybrid Power Systems Workshop | 18 – 19 May 2021
pricing of electricity supply must pursue a general economic
interest while being clearly defined, transparent, non-
discriminatory and verifiable for market participants, see
[15].
In a broader view, there are two basic organizational
patterns for electricity markets: pool-based trading and
bilateral trading, both observable with national modifications
in European member states [17]. The first pattern implies that
all (or most) of the trading activities are coordinated and
observed by the responsible system operator [18]. In
opposite, the bilateral trading typically relies on decentralized
and voluntary markets, organized as over the counter (OTC)
markets or power exchanges. There consumers, generators
and traders are capable to trade electricity in an unrestricted
manner [18]. Both are typically supplemented by an
imbalance settlement process. Exchange-based trading is
typically mandatory in pool-based trading for the spot market
while it there may be competing marketplaces including OTC
markets in bilateral trading systems [17, 18]. In terms of pool-
based trading 2 already directive 96/92/EC required that
eligible customers should have the possibility to conclude
supply contracts with producers to cover their own needs, to
ensure at least some possibility of bilateral trading. This
requirement for instance was satisfied in the UK in the
1990ies by implementing a voluntary forward market to trade
bilateral contracts combined with the obligation for
participating in the Pool when trading electricity [18]. This
requirement has even been tightened by regulation 2019/943
since long-term OTC trading is made an obligation explicitly
for all member states “in order to allow market participants
to be protected against price volatility risks on a market
basis, and mitigate uncertainty on future returns on
investment” [14].
When assessing the conformity of the previously
introduced market design with the basic European
requirements, there are two major aspects to be considered.
On the one hand, the novel market design would introduce
the pool-based trading as organizational pattern for the
electricity market. Although the obligation to facilitate OTC
trading intends to support bilateral trading as organizational
pattern in the EU, it would be possible to integrate this
requirement into the above-mentioned market design. As
long as market participants are obliged to report physical
flows resulting from OTC trading to the responsible system
operator and a participation in the imbalance settlement
process is binding, an efficient allocation of capacity would
be possible. On the other hand, the novel market design is
capable to match the basic principles of transparency,
proportionality and non-discrimination for electricity markets
together with customers’ free choice of suppliers and market-
based supply prices with minimized public interventions.
Considering the existing frameworks for such multi-staged
market clearing processes, e.g., by Caramanis et al. [5],
further work on the foundations is yet required to ensure
transparency and proportionality, especially in terms of the
balancing responsibility of individual market participants.
1) Operational principles
Regulation 2019/943 clearly indicates the binding
principles for operating electricity markets in the EU, see
[14]. Furthermore, member states, regulatory authorities,
system operators, market operators and delegated operators
2 The so-called single buyer procedure, cf. [13].
are responsible for ensuring these principles for all market
participants. While member states must translate and address
these objectives in the corresponding national legislation, the
regulatory authorities are mainly responsible for monitoring
and ensuring compliance of market and system operators as
well as market participants with the rules.
In this regard, regulatory authorities are obliged,
following directive 2019/944, to ensure the most cost-
effective, safe, reliable, and efficient systems that are non-
discriminatory and consumer oriented. These systems should
promote system adequacy, energy efficiency and the
integration of large and small-scale distributed renewable
generation into transmission and distribution networks.
Furthermore, the electricity system shall facilitate its
operation in relation with other energy networks for gas or
heat [15].
These operational principles as well as the obligations of
the regulatory authority, especially with regard to the
sectorial coupling, are matching the incentives and principles
of the previously introduced market design. In detail, the
proposed market design allows for a much better
implementation of these predefined operational principles,
e.g., by facilitating the development of more flexible demand
and generation while delivering appropriate investment
incentives for a sustainable and decarbonized generation and
ensuring a fair competition.
2) Cross-border electricity trade
While regulation 2019/943 and directive 2019/944, set
out the basic framework for cross-border electricity trade and
assign duties and tasks for the relevant entities in the energy
market, regulations 2019/942 and 2015/1222 define detailed
operational rules and methods in this context. To improve the
cross-border electricity trade the EU has granted ACER
additional competences in those areas where national
decisions, with relevance to the cross-border trade of
electricity, may lead to problems for the internal energy
market, see [16]. Thus, the jointly developed and published
network codes of the system operators become regulations.
Especially, the guideline on capacity allocation and
congestion management (CACM), incorporated by regulation
2015/1222, defines the relevant methods for calculating
cross-border electricity flows, based on trading of market
participants, while ensuring system security. This procedure
is known as flow-based market coupling (FBMC).
Furthermore, the operation of European cross border markets
is harmonized [19]. In terms of cross-border electricity trade,
a market coupling operator (MCO) is responsible to match
bids and offers from different bidding zones, for day-ahead
and intraday markets in an optimal manner, while publishing
the FBMC results on a non-discriminatory basis to all power
exchanges, see [19]. The beforehand mentioned cross-border
electricity trade relies on accurate bidding zones reflecting the
distribution of supply and demand. Hereby, bidding zones
may be modified by adjusting, merging, or splitting zone
borders. Nevertheless, this configuration should be consistent
for all market timeframes, i.e., for single day-ahead and
intraday electricity trading, see [19].
There are two perspectives on integrating the novel
market design in a subset of countries or bidding zones in the
EU, when assessing conformity in terms of cross-border
Virtual 5th International Hybrid Power Systems Workshop | 18 – 19 May 2021
electricity trade. On the technical side, the FBMC process
carried out by the MCO can be maintained, e.g., by applying
distributed parallel optimization techniques [20]. In this
context, the algorithms of the corresponding regulation
2015/1222 may need to be adopted to the novel design.
However, the general structure will not change while an
optimal capacity allocation for cross-border electricity trade
can be achieved. However, further investigation in this field
is required since there might be some counterintuitive effects
arising when coupling multiple markets for cross-border
trading when the individual market design relies on different
organizational patterns. On the institutional level, regarding
the regulatory and policy side, the question arises whether the
proposed market design matches the implicitly defined idea
of an internal market for electricity or not. On this side, the
current legislation definitely offers the possibility to
introduce the required changes mentioned beforehand.
However, the implementation of these changes strongly
depends on the idea and the understanding of the internal
market on electricity, thus affecting the political will to
promote the novel market design. Therefore, a precise and
unambiguous assessment at the institutional level requires
further investigations.
C. Congestion management & market-based redispatch
In terms of intrazonal congestion management, Hirth and
Glismann [21] reviewed applicable measures in European
electricity markets available to avoid congestions.
Addressing the case of Germany, as it is integrated into the
European framework, redispatching, including curtailment,
and countertrading are the most relevant measures that
incurred annual costs of more than one billion Euro over the
past three years3. In this context, regulation 2019/943 defines
the regulatory framework for intrazonal redispatching of
generation and load, see [14]. The resources used for
redispatching, shall be selected based on a market-based
mechanism among generation assets, energy storages, or
demand response. Balancing units utilized for redispatching,
are omitted when settling the balancing energy prices.
However, in terms of the present market design in
Germany, research unveiled the possible threats and
disadvantages of a market-based redispatch, due to inc-dec-
gaming in the case of coexisting zonal electricity markets and
local redispatch markets, see [22]. Thus, the coexistence
offers participants of the corresponding markets incentives
for strategic bidding and arbitrage opportunities. Thus, policy
makers decided in close coordination with the regulatory
authority, transmission system operators and experts to
proceed using the cost-based redispatch4, see [23].
In this context, the proposed market design of Section II
would be capable to reduce the drawbacks identified in [22]
inherently. Since, the market clearing is carried out based on
a nodal pricing regime, congestions are taken into account in
a market-based manner while the coexistence of zonal
electricity markets and local redispatch markets can be
precluded.
D. Electricity balancing & reserve procurement
Considering the balancing responsibility of market
participants, both, regulation 2019/943 and directive
3 The procurement of reserve capacity is not taken into account, since, reserve is
intended mainly for system security, frequency containment and restoration, hence,
not mentioned in CACM, i.e., regulation 2015/1222 [16].
2019/944, request transparent proportionate and non-
discriminatory market rules, fees and treatment [14, 15], as
already mentioned in Section B. In addition, regulation
2019/943 defines the regulatory framework for balancing
markets, including e.g., the prequalification processes,
pricing methods, and dimensioning of reserve capacity. In
this context, the applicable areas of the imbalance prices
(reflecting the real-time value of electricity) should
correspond to the previously introduced bidding zones.
However, in terms of central dispatching models, e.g., used
by independent system operators, imbalance price areas
constituting partial biddings zones are allowed [14].
With respect to the proposed market design of Section II,
the interrelation of the market design with energy balancing
is still under investigation. In general, the novel market
design definitely fulfills the generic requirements especially,
e.g., in terms of prequalification processes, pricing methods,
and dimensioning of reserve capacity. However, regarding
the balance responsibility of individual units the question
arises how to ensure non-discrimination and transparency. As
proposed by the novel market design bids must be made on a
unit level and not on a balancing group level. Hence,
aggregators in the novel market design will face a higher
volatility for the scheduled power demand and supply, e.g.,
regarding intermittent RES, compared to the status quo. Even
though, existing frameworks for multi-staged market clearing
processes incorporate reserve procurement as part of the
energy balancing, cf. [5], further research in this direction is
required to derive appropriate instruments for UMs and UOs.
E. Market-based procurement of ancillary services
Distribution and transmission system operators are
obligated, according to directive 2019/944, to procure
ancillary services based on non-discriminatory, transparent,
and market-based procedures [15]. This also incorporates
non-frequency ancillary services, e.g., steady state voltage
control, inertia for local grid stability and black start
capability, unless the regulatory authority granted a
derogation. However, prior to a derogation the market-based
provision of non-frequency ancillary services must be
evaluated as economically inefficient. In terms of the present
market design in Germany, non-frequency ancillary services
have been subject to research, serving as a basis for the
decision for a partial market-based solution of some services,
see [24].
Therefore, the proposed market design of Section II
would complement the market-based short-term procurement
of some ancillary services, by incorporating the requirements
in the market clearing process. For instance, additional LMPs,
e.g., for reserve procurement or for reactive power to provide
a steady state voltage control, see [5], would enable
transparent and verifiable financial incentives for UMs and
UOs to ensure security of supply and local grid stability.
Furthermore, the long-term auctioning or contracting of other
ancillary services, such as black start capability or inertia for
local grid stability, can be carried out regardless of the
underlying market design.
4 Non-market-based downward redispatching, see regulation 2019/943 [13].
Virtual 5th International Hybrid Power Systems Workshop | 18 – 19 May 2021
F. Independent system operators in the EU
Regarding the operation of transmission systems, member
states of the EU are permitted to designate an independent
system operator (ISO). In opposition to ISOs in the US, cf.
[8], European ISOs are typically historically grown by
vertically integrated companies and might be fully state
owned [17, 25]. Therefore, the operational principles and
long-term planning in systems with ISOs in the EU typically
differ from the US American markets [9] and even the
conceptualization of ISOs is partly diverging. However, to
match the differing market design of the member states, the
entire European legislation is designed to fit for both
organizational structures: for TSOs and for ISOs with
separate network owners. For the latter, the regulatory
authority is obligated to ensure an adequate remuneration for
network owners via network access tariffs collected by the
ISO. Therefore, an appropriate remuneration of the network
assets can be ensured while offering incentives for new
investments. Yet, the permission of member states to
establish new ISOs is only foreseen where the transmission
system belonged to a vertically integrated company by
September 3rd, 2009, thus restricting the future establishment
of ISOs [15].
In this context, regulation 2019/943 does not explicitly
prevent the proposed market design from being implemented,
but directive 2019/944 intends the implementation of ISOs
for previously vertically integrated TSOs exclusively. Hence,
the directive would have to be adopted in two ways:
− Permitting the implementation of ISOs while replacing
previously TSOs and separating the network owners
according to the proposed governance structure, cf.
Section II.B.2).
− Permitting the implementation of ISOs for distribution
system operators (DSOs) similar to the TSOs, while the
regulatory authority may grant exemptions regarding the
governance structure, with regard to the establishment of
committees, subcommittees and task forces.
In this context, again the question arises whether the
proposed market design matches the implicitly defined idea
of an internal market for electricity or not. Therefore, the
implementation of the required adoptions strongly depends
on the idea and the understanding of the internal market on
electricity, thus affecting the political will to promote the
novel market design.
IV. CONCLUSION & OUTLOOK
This paper introduced and assessed the relevant aspects of
the regulatory and policy framework applicable to the novel
design of cellular electricity markets. In accordance with the
European legislation, the proposed market design is able to
cope with the existing main principles and rules for electricity
markets. Furthermore, the market design facilitates
opportunities for an improved market-based congestion
management, by utilizing a nodal pricing regime instead of
cost-based redispatching, and for the market-based
procurement of ancillary services. Therefore, inefficiencies
and limitations of present market designs could be addressed
appropriately by unifying the advantages of central markets
and subsidiary energy cell approaches. Furthermore,
regarding the novel market design operational and investment
incentives are provided appropriately, leading to a
coordinated flexibility supply. Introducing novel
organizational patterns for electricity markets, utilizing a
pool-based trading scheme seems to be in line with the
European legislation, if the possibility for OTC trading is
ensured. Finally, the incorporation of local and central ISOs
into the European framework requires an amendment of the
current legislation. Yet, most of the considered legislation
does not preclude the implementation of such a market
design, hence, offering enough flexibility for national policy
makers to prepare first steps. However, in the longer term,
adoptions are required, and the implementation process
strongly depends on the political willingness at the European
level. On this institutional level, the decision on the market
design depends on the European Commission's ideas on the
future of the internal electricity market and the willingness of
the member states to adopt the cross-border trading
mechanisms.
Nevertheless, enabling an economically efficient
integration of millions of mostly small-scale units (RES,
storages etc.) into a central ISO market under consideration
of network restrictions and real-world ICT limitations would
capture the evolving demand of a future energy system. Thus,
the novel market design could provide significant
improvements in comparison to other approaches.
Consequently, even though changes in the European and
national regulatory framework are required, the beforehand
opportunities would justify such changes. Therefore, future
work needs to evaluate the proposed market design,
especially in terms of the following aspects. The proposed
market design requires bids on a unit level, hence, forecasting
errors affecting the settlement of energy imbalances
potentially increase. Furthermore, the cross-sectoral market
coordination (comprising the electricity, heat and gas sector)
needs to be addressed in more detail.
V. ACKNOWLEDGMENT
The work has been carried out as part of the research
project ZellNetz2050 which is funded by the Federal Ministry
for Economic Affairs and Energy under grant agreement
number 0350065C.
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Virtual 5th International Hybrid Power Systems Workshop | 18 – 19 May 2021
