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PROYECTO FIN DE CARRERA
Regulatory analysis for the integration of
Distributed Generation and Demand-Side
Participation
AUTOR: Breogán Pardo Álvarez
DIRECTOR: David Trebolle Trebolle
MADRID, Mayo 2013
UNIVERSIDAD PONTIFICIA COMILLAS
ESCUELA TÉCNICA SUPERIOR DE INGENIERÍA (ICAI)
INGENIERO INDUSTRIAL
AUTORIZACIÓN PARA LA DIGITALIZACIÓN, DEPÓSITO Y DIVULGACIÓN EN ACCESO
ABIERTO (RESTRINGIDO) DE DOCUMENTACIÓN
1º. Declaración de la autoría y acreditación de la misma.
El autor D. Breogán Pardo Álvarez, como alumno de la UNIVERSIDAD PONTIFICIA COMILLAS
(COMILLAS), DECLARA
que es el titular de los derechos de propiedad intelectual, objeto de la presente cesión, en
relación con la obra Proyecto Fin de Carrera “Análisis Regulatorio para la implementación de la
GD y la Participación Activa de la Demanda1, que ésta es una obra original, y que ostenta la
condición de autor en el sentido que otorga la Ley de Propiedad Intelectual como titular único
o cotitular de la obra.
En caso de ser cotitular, el autor (firmante) declara asimismo que cuenta con el
consentimiento de los restantes titulares para hacer la presente cesión. En caso de previa
cesión a terceros de derechos de explotación de la obra, el autor declara que tiene la oportuna
autorización de dichos titulares de derechos a los fines de esta cesión o bien que retiene la
facultad de ceder estos derechos en la forma prevista en la presente cesión y así lo acredita.
2º. Objeto y fines de la cesión.
Con el fin de dar la máxima difusión a la obra citada a través del Repositorio institucional de la
Universidad y hacer posible su utilización de forma libre y gratuita ( con las limitaciones que
más adelante se detallan) por todos los usuarios del repositorio y del portal e-ciencia, el autor
CEDE a la Universidad Pontificia Comillas de forma gratuita y no exclusiva, por el máximo plazo
legal y con ámbito universal, los derechos de digitalización, de archivo, de reproducción, de
distribución, de comunicación pública, incluido el derecho de puesta a disposición electrónica,
tal y como se describen en la Ley de Propiedad Intelectual. El derecho de transformación se
cede a los únicos efectos de lo dispuesto en la letra (a) del apartado siguiente.
3º. Condiciones de la cesión.
Sin perjuicio de la titularidad de la obra, que sigue correspondiendo a su autor, la cesión de
derechos contemplada en esta licencia, el repositorio institucional podrá:
(a) Transformarla para adaptarla a cualquier tecnología susceptible de incorporarla a internet;
realizar adaptaciones para hacer posible la utilización de la obra en formatos electrónicos, así
como incorporar metadatos para realizar el registro de la obra e incorporar “marcas de agua”
o cualquier otro sistema de seguridad o de protección.
(b) Reproducirla en un soporte digital para su incorporación a una base de datos electrónica,
incluyendo el derecho de reproducir y almacenar la obra en servidores, a los efectos de
garantizar su seguridad, conservación y preservar el formato. .
1 Especificar si es una tesis doctoral, proyecto fin de carrera, proyecto fin de Máster o cualquier otro
trabajo que deba ser objeto de evaluación académica
(c) Comunicarla y ponerla a disposición del público a través de un archivo abierto institucional,
accesible de modo libre y gratuito a través de internet.2
(d) Distribuir copias electrónicas de la obra a los usuarios en un soporte digital. 3
4º. Derechos del autor.
El autor, en tanto que titular de una obra que cede con carácter no exclusivo a la Universidad
por medio de su registro en el Repositorio Institucional tiene derecho a:
a) A que la Universidad identifique claramente su nombre como el autor o propietario de los
derechos del documento.
b) Comunicar y dar publicidad a la obra en la versión que ceda y en otras posteriores a través
de cualquier medio.
c) Solicitar la retirada de la obra del repositorio por causa justificada. A tal fin deberá ponerse
en contacto con el vicerrector/a de investigación ([email protected]).
d) Autorizar expresamente a COMILLAS para, en su caso, realizar los trámites necesarios para
la obtención del ISBN.
d) Recibir notificación fehaciente de cualquier reclamación que puedan formular terceras
personas en relación con la obra y, en particular, de reclamaciones relativas a los derechos de
propiedad intelectual sobre ella.
5º. Deberes del autor.
El autor se compromete a:
a) Garantizar que el compromiso que adquiere mediante el presente escrito no infringe ningún
derecho de terceros, ya sean de propiedad industrial, intelectual o cualquier otro.
b) Garantizar que el contenido de las obras no atenta contra los derechos al honor, a la
intimidad y a la imagen de terceros.
c) Asumir toda reclamación o responsabilidad, incluyendo las indemnizaciones por daños, que
pudieran ejercitarse contra la Universidad por terceros que vieran infringidos sus derechos e
intereses a causa de la cesión.
d) Asumir la responsabilidad en el caso de que las instituciones fueran condenadas por
infracción de derechos derivada de las obras objeto de la cesión.
2 En el supuesto de que el autor opte por el acceso restringido, este apartado quedaría redactado en los
siguientes términos: (c) Comunicarla y ponerla a disposición del público a través de un archivo institucional, accesible de modo restringido, en los términos previstos en el Reglamento del Repositorio Institucional 3 En el supuesto de que el autor opte por el acceso restringido, este apartado quedaría eliminado.
6º. Fines y funcionamiento del Repositorio Institucional.
La obra se pondrá a disposición de los usuarios para que hagan de ella un uso justo y
respetuoso con los derechos del autor, según lo permitido por la legislación aplicable, y con
fines de estudio, investigación, o cualquier otro fin lícito. Con dicha finalidad, la Universidad
asume los siguientes deberes y se reserva las siguientes facultades:
a) Deberes del repositorio Institucional:
- La Universidad informará a los usuarios del archivo sobre los usos permitidos, y no garantiza
ni asume responsabilidad alguna por otras formas en que los usuarios hagan un uso posterior
de las obras no conforme con la legislación vigente. El uso posterior, más allá de la copia
privada, requerirá que se cite la fuente y se reconozca la autoría, que no se obtenga beneficio
comercial, y que no se realicen obras derivadas.
- La Universidad no revisará el contenido de las obras, que en todo caso permanecerá bajo la
responsabilidad exclusiva del autor y no estará obligada a ejercitar acciones legales en nombre
del autor en el supuesto de infracciones a derechos de propiedad intelectual derivados del
depósito y archivo de las obras. El autor renuncia a cualquier reclamación frente a la
Universidad por las formas no ajustadas a la legislación vigente en que los usuarios hagan uso
de las obras.
- La Universidad adoptará las medidas necesarias para la preservación de la obra en un
futuro.
b) Derechos que se reserva el Repositorio institucional respecto de las obras en él registradas:
- retirar la obra, previa notificación al autor, en supuestos suficientemente justificados, o en
caso de reclamaciones de terceros.
Madrid, a 31 de mayo de 2013
ACEPTA
Fdo……………………………………………………………
Proyecto realizado por el alumno/a:
Breogán Pardo Álvarez
Fdo.: …………………… Fecha: ……/ ……/ ……
Autorizada la entrega del proyecto cuya información no es de carácter confidencial
EL DIRECTOR DEL PROYECTO
David Trebolle Trebolle
Fdo.: …………………… Fecha: ……/ ……/ ……
Vº Bº DEL COORDINADOR DE PROYECTOS
Prof. Dr. Fernando de Cuadra García
Fdo.: …………………… Fecha: ……/ ……/ ……
PROYECTO FIN DE CARRERA
Regulatory analysis for the integration of
Distributed Generation and Demand-side
participation
AUTOR: Breogán Pardo Álvarez
DIRECTOR: David Trebolle Trebolle
MADRID, Mayo 2013
UNIVERSIDAD PONTIFICIA COMILLAS
ESCUELA TÉCNICA SUPERIOR DE INGENIERÍA (ICAI)
INGENIERO INDUSTRIAL
I
ANÁLISIS REGULATORIO PARA LA IMPLEMENTACIÓN DE LA
GENERACIÓN DISTRIBUIDA Y LA PARTICIPACIÓN ACTIVA DE
LA DEMANDA.
Autor: Pardo Álvarez, Breogán.
Director: Trebolle Trebolle, David.
Entidad Colaboradora: Unión Gas Natural Fenosa.
RESUMEN DEL PROYECTO El proceso de liberalización y separación de actividades del sector eléctrico que empezó
en la década de los 90 en la mayoría de los países europeos, ha supuesto un cambio en
su estructura. Generación, mercados eléctricos (mercados mayorista y minorista) son
actividades liberalizadas, mientras que las actividades de red (transporte y distribución),
gestión técnica y operador del mercado (si existe) permanecen como actividades
reguladas.
Todas las actividades del sector eléctrico se agrupan en cuatro grupos: capa física,
gestión técnica, actividades económicas y marco regulatorio. Esta división es importante
a la hora de entender el análisis presentado en este proyecto.
En los últimos años, la concienciación del impacto medioambiental debido a la
actividad humana, la dependencia exterior de la UE de materias primas (combustibles
fósiles) y la insostenibilidad de los sistemas energéticos han motivado cambios en las
políticas energéticas. Un ejemplo de ello son los objetivos 20/20/20 para el 2020 que
tratan de solucionar los problemas que se acaban de mencionar.
Dentro de la demanda energética de un país, el sistema eléctrico supone una gran
proporción de dicha demanda. Por ello, se requiere que el sistema eléctrico se desarrolle
de una manera más inteligente y activa evolucionando hacia las “Redes Eléctricas
Inteligentes”.
Las redes eléctricas inteligentes son la evolución del sistema eléctrico actual, son el
proceso de integración de los Recursos Energéticos Distribuidos (RED) al mismo
tiempo que se mejora la calidad, eficiencia y seguridad del suministro. Los RED son:
Generación Distribuida (GD), Participación Activa de la Demanda (PAD), Vehículo
eléctrico y almacenamiento descentralizado. Complementariamente, es imprescindible
un adecuado desarrollo tecnológico y marco regulatorio para la buena integración de los
RED.
Hay dos aspectos muy importantes a considerar:
Las redes inteligentes son un proceso de integración de los RED, por lo que no
suponen un tipo totalmente nuevo de redes con activos de red que descarten a los
actuales. Como todo proceso de evolución, las redes inteligentes tienen una hoja de
ruta en la que algunos RED han de integrarse antes que otros.
Los RED debido a sus características, son activos que se conectarán a la red de
distribución, en consecuencia, estas redes juegan un papel fundamental en la
evolución de las redes inteligentes.
Actualmente, la integración de los RED está suponiendo grandes retos para los
distribuidores que suponen un impedimento para su adecuada integración.
II
Generación Distribuida (GD)
Se considera generación distribuida (GD) aquellos sistemas de generación eléctrica
conectados a la red de distribución, caracterizados por su poca potencia y por estar
conectados cerca del consumo final.
Sólo bajo ciertas hipótesis, la GD puede reducir las pérdidas eléctricas, retrasar las
inversiones del Operador del Sistema de Distribución (OSD) en la red y mejorar la
seguridad de suministro. Sin embargo, la realidad es otra muy distinta.
En los últimos años, las Autoridades Regulatorias Nacionales (ANR) de Europa han
llevado a cabo planes de incentivos para la GD de carácter renovables. Estos incentivos
se otorgaron a las energías renovables por:
Alto coste medio de producción de energía: las renovables hace pocos años
estaban en sus inicios y por tanto, eran tecnologías inmaduras incapaces de competir
en los mercados eléctricos. Actualmente, algunas tecnologías renovables (eólica
terrestre y geotérmica) presentan unos costes comparables a las tecnologías
convencionales.
Su naturaleza intermitente e impredecible hacen muy difícil su participación en
los mercados eléctricos.
Estos dos factores unidos hicieron que la GD renovable (que supone una parte
importante de la GD) obtuviera ayudas como: prioridad de acceso y mecanismo de
ayudas económicas (tarifas feed-in, cuotas + certificados verdes, etc.). Las
consecuencias de dichas ayudas han sido que:
GD renovable no participe en los mercados eléctricos y el DSO no reciba ninguna
información sobre la potencia que inyecta la GD en sus redes.
GD renovables pueden inyectar potencia en la red a cualquier hora del día sin tener
en cuenta el estado de la red a la que se conectan.
En cuanto a la planificación, el principal problema de la GD es su falta de firmeza
(capacidad de un grupo generador para inyectar/absorber potencia cuando el sistema lo
requiere). Por este motivo, los OSD no pueden confiar en la capacidad de la GD y
planifican redes sin tener la GD en cuenta, resultando en sistemas sobredimensionados.
Respecto a la operación, la integración de la GD (cargas impredecibles y flujos de
potencia bidireccional) en las redes de distribución, requiere que los OSD pasen de una
operación pasiva a una operación más activa y flexible. La GD tiene principalmente dos
efectos negativos.
En primer lugar, en las redes de MT y BT, la potencia activa inyectada por la GD
produce grandes variaciones de tensión, afectando a la calidad del producto final para el
cliente. Para compensar dicho efecto es necesario controlar los flujos de potencia
reactiva. Sin embargo, en líneas de MT y BT el efecto de la potencia reactiva sobre la
tensión es mucho menor que el de la potencia activa.
En segundo lugar, puede haber congestiones en el sistema (PG-PL>Pmáx) que lleven al
sistema fuera de la operación segura. Como se mencionó antes, esto es debido
principalmente a la ausencia de incentivos para que la GD considere el estado de
operación, a nivel local, de la red a la que se conecta.
III
En lo que respecta a la forma de conexión y acceso de la GD, es necesario abandonar el
método tradicional de “Fit and forget” (sólo se analiza el impacto de la GD en la
planificación y acceso firme) y avanzar hacia una “Gestión activa” (considera el
impacto de la GD en la planificación y luego en la operación, puede o no tener acceso a
la red) ya que es la solución más económica y eficiente.
Dentro de la conexión de la GD existen los siguientes problemas:
Criterios técnicos de conexión: criterios de protecciones eléctricas no adecuados, la
no posibilidad de usar cargos por conexión semidirectos en vez de los cargos por
conexión profundos.
Ausencia de transversalidad a nivel nacional, falta de estandarización, falta de
transparencia, criterios discriminatorios de algunos generadores respecto de otros.
Debido al “fit and forget”, la GD tiene acceso firme a la red. Si la GD genera cuando el
sistema está al límite de la operación segura, puede provocar apagones y cortes de
suministro que reducen así la fiabilidad del mismo.
Además de todo lo anterior, OSD necesitan integrar en sus redes las TICs para mejorar
la monitorización de sus redes y establecer comunicaciones bidireccionales con la GD.
Participación Activa de la Demanda (PAD).
El término de PAD se usa como un concepto que engloba otros dos:
Gestión Activa de la Demanda (GAD): es la implementación de todas aquellas
medidas (por parte de los OSD) que tratan de influenciar la manera en que se
consume la energía, obteniendo los cambios deseados en la curva de la demanda.
Estas medidas se pueden clasificar en cuatro grupos: mejorar la eficiencia del
sistema, trasladar demanda de los picos a los valles, rellenar los valles y reducir la
demanda en momentos críticos para el sistema.
Respuesta de la demanda (RD): se refiere a los cambios en los hábitos de consumo
de los consumidores finales debidos a las variaciones de las señales de precios a lo
largo del tiempo.
La demanda de cualquier sistema eléctrico está caracterizada por: comportamiento
estacional, relación entre picos y valles, eventos especiales, dispersión geográfica de la
generación y la demanda, tipo de demanda (industrial, servicios y consumo doméstico)
e inelasticidad. La inelasticidad de la demanda impide la integración de la RD. Esto se
debe a dos factores:
El cliente final carece de información acerca del precio real de la electricidad. Para
subsanar esto, es necesario que el cliente final pueda recibir señales de precio.
Gran parte de la demanda (pequeñas industrias, servicios y consumos domésticos)
presentan tarifas reguladas con precios más o menos constantes, siendo necesario
integrar contratos que reflejen el precio de la electricidad en los mercados eléctricos.
Estos dos factores hacen que el cliente final no sea consciente de los precios finales y
carezcan de incentivos para adaptar su consumo según los precios del mercado y el
estado del sistema.
Desde el punto de vista de la planificación, el DSO debe procurar firmeza en la
demanda (reducir o parar su consumo cuando el sistema lo requiere) para poder retrasar
IV
sus inversiones en refuerzos de red, mejorando la utilización de los activos existentes.
En cuanto a la operación, la RD puede ayudar a gestionar congestiones cuando haya
exceso de demanda.
Además de todo esto, la adecuada integración y coordinación de la GD y la PAD, los
OSD deben desarrollar herramientas para mejorar su monitorización, previsión de
demanda, simulación y control de sus redes.
Modelo regulatorio propuesto: soluciones para la integración de la GD y la
PAD dentro del marco de las Redes Eléctricas Inteligentes.
En la planificación, los OSD necesitan mejorar la firmeza de la demanda y de la GD.
Para este propósito, las ANR deben definir los mercados de gestión de capacidad
firme para incentivar dicha firmeza de la GD y de la demanda.
Dentro de los mercados de gestión de firmeza de capacidad hay dos tipos de mercados:
los de firmeza de la GD y los de firmeza de la demanda. Gracias a la firmeza obtenida
en estos mercados, los OSD pueden obtener capacidad extra de la GD o reducir la
capacidad de la demanda (a través de comercializadoras y grandes consumidores) en
aquellos momentos en los que la red, localmente, vaya a estar sobrecargada. De esta
manera los OSD podrán retrasar las inversiones de refuerzo de la red.
Estos mercados deberían ser coordinados por los OSD, ya que son los que mejor
conocen el funcionamiento de sus redes. Habrá tantos mercados como áreas en las que
dividan los OSD sus redes, ya que estos mercados son locales.
Los OSD establecerán estos mercados con un plazo mínimo de un año, basándose en
sus previsiones de demanda para ese periodo de un año. Por ello, deben determinar las
áreas y el número de horas que se espera que el sistema esté sobrecargado. El uso de
este servicio debería ser ex-post, de manera que el OSD sólo pague por este servicio a la
GD, comercializadoras y/o grandes consumidores cuando haga uso de él y al precio
establecido en estos mercados. Los OSD pagarán por estos servicios (OPEX) hasta el
momento en el que investir en refuerzos (CAPEX) a largo plazo sea lo más
económicamente eficiente.
Respecto a la filosofía de conexión y acceso de la GD, los OSD tienen que evolucionar
hacia una “Gestión Activa” (conexión y acceso no firmes) que busca la solución más
económica para el corto y el largo plazo. Los OSD deberían incentivar que la GD acepte
estos contratos de acceso variable a cambio de beneficios económicos en la conexión
(usar cargos por conexión semidirecta en vez de cargos por conexión profundos). Estos
contratos permitirán a los OSD restringir la inyección de potencia de la GD cuando el
sistema esté congestionado durante la operación.
Para la conexión de la GD, las ARN deberían definir criterios de protección adecuados
para cada tecnología, evitando la desconexión de GD ante perturbaciones en la red,
recomendándose el uso de estándares internacionales como las normas UNE o IEC. Las
ARN deberían permitir que los OSD ofrezcan a la GD cargos por conexión semidirecta
para incentivar su apoyo en la operación y planificación a través de los servicios de
sistema (firmeza, control de tensión, compensación de pérdidas, etc.). Además, las
ANR deberían establecer como obligatorio la implantación de las TICs para establecer
comunicaciones entre OSD y GD.
V
En cuanto al acceso y conexión de la demanda, sólo destacar que en la conexión es
imprescindible el establecer programas de implementación gradual de los contadores
inteligentes para todos los consumidores finales.
En lo referente a la operación, las ARN deberían definir tres estados distintos de
operación del sistema:
Estado normal: el sistema está dentro de los límites de operación segura.
Estado de alerta: la curva de demanda acordada en el mercado mayorista puede
provocar congestiones, variaciones de tensión y otros problemas a nivel local que
requieren la utilización de servicios de sistema. Estos servicios de sistema
proporcionados por los RED, serán coordinados mediante mercados por los OSD.
Estado de emergencia: el sistema ha pasado los límites de operación segura y
requiere la intervención inmediata de los OSD para solventar los problemas cuanto
antes.
Los OSD utilizarán los servicios de sistema para pasar de los estados de alerta o
emergencia al estado normal. Las ANR deben crear dichos servicios de sistema.
Además, para que OSD puedan coordinar los RED y los servicios de sistema que
proporcionan, los OSD necesitan invertir en TICS, creación de los mercados de
servicios de sistema y herramientas de monitorización, simulación, previsión de carga y
control.
Las ARN deberían considerar los OPEX y CAPEX derivados de la implementación de
las TICs, mercados de servicios de sistema y nuevas herramientas para los OSD. Por
ello, las ANR deberían desarrollar una regulación por incentivos de los OPEX y los
CAPEX. Al mismo tiempo será imprescindible la definición de indicadores que
controlen el grado de implementación y variables económicas de las nuevas soluciones
en el caso de los CAPEX e indicadores de calidad, eficiencia, seguridad y variables
económicas en el caso de los OPEX.
Las ayudas para la integración de nuevas tecnologías en la GD deben procurar el
desarrollo tecnológico al mismo tiempo que se procura limitar la inserción a gran
escala de tecnología inmadura en los sistemas de distribución. Para conseguir esto, las
ANR deberían determinar una cantidad fija de presupuestos para estas ayudas. En
segundo lugar, deberían repartir dicha cantidad de manera que: tecnologías inmaduras
reciban una menor proporción del total, pero que esa cantidad se reparta entre menos
proyectos (limita el número de proyectos). Por el contrario, tecnologías más maduras
recibirán una mayor proporción del total, pero se repartirá entre más proyectos.
Finalmente, las ANR tienen que decidir si las ayudas las obtienen de la tarifa de acceso
o si las obtienen a través de los Presupuestos Generales del Estado. Ambas opciones
tienen consecuencias negativas a corto plazo, pero son imprescindibles para la
competitividad del país a largo plazo.
Para la integración de la respuesta de la demanda hay dos elementos clave: contratos
basados en precios del mercado y señales de precios a través de contadores inteligentes.
Las comercializadoras deben crear productos atractivos para sus clientes objetivo, de
manera que de forma voluntaria abandonen los contratos regulados. Además, los
consumidores finales pueden obtener beneficios si trasladan su consumo a momentos de
menor demanda o cuando el sistema lo requiera (incentivos de los mercados de
firmeza).
VI
VII
REGULATORY ANALISYS FOR THE INTEGRATION OF
DISTRIBUTED GENERATION AND DEMAND-SIDE
PARTICIPATION.
Summary of the dissertation.
The de-regulation and unbundling process of the electrical sectors that started in the
90’s in most of European countries, has change their structure. Generation, economic
activities (wholesale and retail markets) are de-regulated activities, while network
activities (transmission and distribution), technical operation and market operator (when
it exists) are regulated activities.
The activities involved in the electrical sector can be divided in four groups: physical
layer, technical management layer, economic activities and regulatory framework. This
separation is essential for the analysis of the smart grids presented in this dissertation.
In recent years, the awareness about the environmental impact derived from human
activities, the external fossil fuel’s dependence of Europe and the unsustainability of the
energy system have motivated changes in the energy policies of the EU. As a result of
this tendency, new milestones such as the objectives 20/20/20 for 2020 try to solve the
three aforementioned issues.
The electrical systems represent an important share of the energetic demand of any
country; thereafter, changes in the electrical systems are required if the EU wants to
achieve its objectives. In order to face these new challenges, the electrical systems must
be developed with a smarter and more active approach. Electrical systems must evolve
towards “Electrical Smart Grids”.
The electrical smart grids are the evolution of the current electrical systems, the
implementation process of the Distributed Energetic Resources (DER) at the same time
that improving the quality, security and efficiency of the system. The DER are:
Distributed Generation (D.G.), Demand-side Participation (DSP), Electric vehicle and
Decentralized Storage. However, the development of the technology and proper
regulatory frameworks are remarkably important for the proper implementation of the
DER.
It is important to highlight two aspects:
The Smart Grids are an integration process of the DER; therefore, they are not a
totally new type of networks with new lines and equipment that substitutes the
current one. As any evolution process there is a path that must be followed and
some DER must be integrated before some others (DG and DSP must be
integrated before decentralized storage and the electric vehicle).
The DER due to their characteristics will be connected to the distribution
networks; thereby, the integration of the DER requires the proper evolution of
the current distribution networks to accommodate these DERs.
The integration of the DER in the current distribution networks are facing several
problems that are preventing their proper integration in such networks.
VIII
Distributed Generation
Distributed generation (DG) refers to electric generation systems connected to the
distribution network, which are characterized by their low power and their near
location to the load or consumption.
Only under certain boundary conditions the DG can bring to the distribution networks
the following benefits:
Lower electrical losses.
Deferral of the investments required to reinforce the network.
Better security of supply service.
Nonetheless, the way in which DG is being connected to the network is bringing the
opposite effects.
Recently, the European National Regulatory Authorities (NRA) have incentivize the
deployment of Renewable Energy Sources (RES) in DG. These incentives were mainly
due to:
High levelized costs of energy: at the beginning the RES were immature
technologies and they were not able to compete in the electrical markets. Presently,
some of these technologies such as geothermal and on-shore wind power have
levelized costs comparable to those of conventional technologies.
Their intermittent and unpredictable nature makes very difficult for these
technologies to participate in the energy markets.
These two factors combined motivated that DG RES (which account for an important
share of DG) obtain some benefits such as: priority access and economic support
mechanisms (feed-in tariffs, fees and green certificates, etc.). These benefits have
resulted in:
DG RES do not participate in the energy markets and DSOs do not receive any
information about their schedule and dispatching.
DG RES can inject power in the distribution networks at any time without
considering the actual state of the local distribution network where it is connected..
In the planning step, the main problem that DSOs have to face is the lack of firmness
(capacity of a generator to produce/ absorb power when it is required by the system) of
DG. Because of this, DSOs cannot rely on the capacity provided by DG and they have
to reinforce the network to endure the negative effects of the DG.
In the operation step, the integration in the networks of DG (non-predictable load and
bidirectional power flows) requires DSOs to shift from the traditional passive approach
of operation to a more active operation. The DG has 2 negative effects which lead the
local distribution network to alert state.
Firstly, in the medium and low voltage distribution networks (MV and LV networks),
the active power injected by DG produce voltage variations, affecting the quality of the
electricity. To compensate this effect, it is necessary to control the flow of reactive
power. However, reactive power in the MV and LV networks has little effect on
voltage control. This situation results in problem for DSOs to accomplish their tasks.
IX
Secondly, there can be congestions in local area of the distribution network (PG-
PL>Pmax or PL-PG>Pmax) leading the system beyond the security limits. This is mainly
due to the lack of incentives for DG to consider the state of the distribution network in
the area where it is connected.
Regarding the connection and access of the DG, it is necessary to move from the
traditional “Fit and forget approach” to a more “Active management approach”, being
the more cost effective solution.
Within the connection of DG there are the following problems:
Technical connection criteria: bad criteria for electrical protections, no possibility
to use shallower connection charges instead of deep connection charges.
Lack of homogeneous national criteria, standardization, transparency and non-
discrimination.
Regarding the access of DG, as mentioned before, the DG has priority access and
support mechanisms that allow DG RES feed-in at any time. This can lead the
distribution networks to blackouts and curtailments when the security limits are
surpassed (decreasing reliability).
On top of that, DSOs need to invest in the integration of ITCs to improve their
monitoring of the network and establish bidirectional communication with DG.
Demand-side Participation
Demand-side participation is a concept that embodies two other concepts:
Demand-side Management (DSM): implementation of those actions aiming to
influence on the way that energy is consumed, obtaining the desired changes in the
demand curve. These actions oriented to influence the demand are introduced by
DSOs and they can be classified in 4 categories: improve overall efficiency of the
system, shift demand from peak to valleys, fill valleys and reduce demand in critical
moments for the system.
Demand Response (DR): involves all the changes in end-users’ normal consumption
patterns due to variations on price signals over the time.
The demand of any electrical system is characterized by: seasonal behaviour, peak-
valley ratios, especial events, geographic dispersion, type of demand (industrial, service
and household) and price inelasticity.
From the demand response point of view, the most important of these characteristics is
the inelasticity of the demand. This is mainly due to two factors:
Final customer’s lack of information about the actual price of the electricity. For this
aspect, the integration of the smart meters will be crucial for final customers to
receive price signals from the energy markets or their energy suppliers.
A significant part of the demand (small industrial, services and household
consumption) has regulated contracts with static prices.
X
These two factors combined make that final customers cannot be aware of prices and
lack of incentives to modify their consumption habits when the system requires it or
when the prices of the electrical markets are high.
From a planning point of view, ensuring the firmness of demand (reduce/stop
consuming when the system requires it) can be an important tool for DSOs (DSM) to
plan their networks in a more efficient way, postponing reinforcements of the networks.
Furthermore, in the operation step demand response can be used by DSOs to manage
congestions in the system.
For the proper integration of DG and DSP, DSOs need to develop new tools that will
improve their visibility of the system and also will improve the planning and the
operation of their networks. Therefore, DSOs should invest in monitoring, simulation,
control and forecasting tools.
Proposed regulatory model: Solutions for the integration of DG and DSP
within the framework of the Smart Grids.
In the planning step, DSOs need to increase the firmness of the demand and the DG. For
this purpose, NRA should allow DSOs to integrate firm DG/ Demand and create the so
called “firm capacity management markets”.
Within the firm capacity management markets there are two types: the firm DG and
firm demand capacity markets. Because of firm DG capacity markets, DSOs can obtain
extra capacity from DG to postpone investments in reinforcements. At the same time,
the firm demand capacity markets will enable DSOs to incentivize energy suppliers/
large customers to reduce their demanded capacity in some moments when the local
area would be overloaded. Both of these markets try to use demand or DG to provide
the necessary capacity without reinforcing the network.
These markets should be co-ordinated by DSOs, since they are the ones who better
know the functioning of their networks. There are as many markets as areas defined by
the DSOs because they consider the local generation and demand.
The DSOs based on the expected future demand, must foresee the areas and the number
of hours in the year when the network might be overloaded. These services would be
paid by DSOs ex-post. This means that in these markets, the price of the service is
established and only when the DSOs make use of it, the DSOs will pay to the DG/
energy suppliers/ large customers.
The DSOs will procure this services (OPEX) until the moment on which investing in
reinforcements of the network (CAPEX) in the long-term time scale breaks even.
Regarding the connection and access of DG, DSOs have to evolve towards an “Active
management approach” (non-firm connection, non-firm access) since it chases the most
cost-effective solution between OPEX and CAPEX. DSOs should incentivize DG
developer to accept non-firm access contracts in reward of benefits in the connection
charges (use shallower instead of deep connection charges). Non-firm access contracts
will allow DSOs to curtail DG feed-in when congestions occur during the operation.
For the connection of DG, NRA should define proper protection criteria (strongly
recommend UNE or IEC) for each type of technology ensuring the security of the
system. NRA should allow DSOs to offer DG shallower connection charges for those
XI
DG who offer system services (firmness, DSO voltage control, losses compensation,
etc.). Additionally, NRA should define as obligatory the integration of ITCs for the
communication between the DSOs and the DG. For the connection of the demand, the
most important component is the smart meter.
In the operation step, a model based on system’s states is recommended. The
distribution system has three different states:
Normal state: the system runs smoothly and no constraints are being violated.
Alert state: the distribution system (locally or the whole) goes beyond the security
limits due to voltage variations, congestions, etc. To solve these problems, the DSO
will purchase system services (services offered by the DER to the DSOs), which are
based on commercial agreements, to come back to the normal state.
Emergency state: the system (locally or the whole) goes beyond the safe operation
boundaries. For this case, the DSOs will actively influence on the generation/
demand to solve the problems, without considering the commercial agreements, as
soon as possible. Compensation criteria should be defined for this case.
NRAs need to incentivize DSOs to invest in those technologies required in order to
integrate the DERs and their system services to support DSOs in their tasks. DSOs
should invest in: implementation of ITCs, creation of system services markets and tools
(monitoring, simulation, control and forecasting) for co-ordination.
NRA should consider the OPEX and CAPEX derived from these solutions, to
incentivize its gradual integration. For this purpose, NRAs should follow an incentive
based regulation of CAPEX and OPEX at the same time that creating KPIs that
measure the integration level of the new technologies, the quality, the efficiency, the
security and economic variables considering the most cost effective solution.
The subsidies for the integration of new technology in DG should be done in a way that
incentivizes the technological development, becoming more competitive at the same
time that limiting the integration of high shares of immature DG in the system. For this
purpose, NRAs should establish a fix amount of total subsidies. Then, they should
provide with higher proportion of the total to more mature technologies, but providing
less money by project. Conversely, for less mature technologies, a smaller proportion
of the total budget should be devoted, but more money per project. NRAs have to
decide according to their energy policy whether the subsidies are withdrawn from the
access tariff or the National State budget. Both options have negative effects in the
short-term time scale, although the technological development is essential for
improving the competence of the country in the long-term time scale.
For the integration of the DR, there are two basic components: market-reflective
contracts and price signals through smart meters. Energy suppliers must define
attractive products that adjust to their target customer consumption habits, motivating
their voluntary shift from regulated contracts to de-regulated contracts. Additionally,
final customers can obtain potential benefits if they decide to shift their consumption to
those hours with lower energy market prices or when the system requires it (incentives
from firm demand capacity markets).
XII
XIII
Index
1. Introduction, motivation and objectives. ............................. 1
1.1 Introduction and motivation .................................................................................. 1
1.2 Objectives ............................................................................................................... 2
2. The current electrical system in Spain. ................................ 5
2.1 Physical layer .......................................................................................................... 5
2.2 Technical management. ......................................................................................... 7
2.3 Economic management level. ................................................................................ 8
2.3.1 Electricity markets ........................................................................................ 10
2.3.1.1 Wholesale market ................................................................................. 10
2.3.1.2 Retail market ......................................................................................... 18
2.4 Regulatory framework .......................................................................................... 19
2.4.1 Structure of the electrical sector. ................................................................. 19
2.4.2 Regulation of the distribution activity .......................................................... 19
2.4.3 Quality of service, Security and Efficiency. ................................................... 20
3. The evolution of the current electrical system: Smart .........
Grids. ...................................................................................... 21
3.1 Reasons for the change of the current electrical system. .................................... 21
3.2 Concept of Smart Grids ........................................................................................ 24
4. Distributed Energetic Resources (DER). ............................ 29
4.1 Distributed Generation (DG). ............................................................................... 29
4.1.1 Definitions. .................................................................................................... 29
4.1.2 Market accessibility ...................................................................................... 30
4.1.2.1 Costs of technologies deployed in DG. .................................................. 30
4.1.2.2 Priority access and support mechanisms for the integration of
renewable energy technologies. ......................................................................... 31
4.1.2.3 Objective of subsidies for new technologies. ........................................ 33
XIV
4.1.3 Planning ........................................................................................................ 34
4.1.4 Operation ...................................................................................................... 37
4.1.5 Connection and Access ................................................................................. 45
4.1.6 Information exchange ................................................................................... 52
4.2 Demand-side Participation (DSP) ......................................................................... 54
4.2.1 Definitions. .................................................................................................... 54
4.2.2 Demand characteristics ................................................................................ 56
4.2.3 Lack of demand participation in energy markets: Inelastic demand ........... 58
4.2.4 Planning. ....................................................................................................... 61
4.2.5 Operation. ..................................................................................................... 62
4.2.6 Technology and information exchange ........................................................ 64
5. The new role of the DSO and regulatory framework ..........
recommendations. ................................................................. 69
5.1 Planning. ............................................................................................................... 69
5.1.1 Firmness of DG. ............................................................................................. 69
5.1.2 Firmness of Demand ..................................................................................... 70
5.1.3 Firm capacity management: Firmness markets for DG and Demand. .......... 71
5.1.3.1 Functioning of firm DG capacity markets. ............................................. 71
5.1.3.2 Firm Demand capacity markets. ............................................................ 73
5.2 Connection and Access ......................................................................................... 75
5.2.1 Connection and access requirement for DSO ............................................... 75
5.2.1.1 Connection based on Active management approach. .......................... 76
5.2.1.2 Network access based on Active Management Approach. ................... 76
5.2.2 Connection and access requirements for DG and Demand ......................... 78
5.2.2.1 Connection requirements from DG’s point of view. ............................. 78
5.2.2.2 Connection requirements from demand response’s point of view. ..... 80
5.2.2.3 Access requirements from DG’s point of view. ..................................... 81
5.3 Operation ............................................................................................................. 81
XV
5.3.1 System state model and system services as tools for the DSO. ................... 81
5.3.2 Concept of system services and system services required for each state of
the system. .................................................................................................................. 82
5.3.2.1 System services definition. .................................................................... 82
5.3.2.2 System services required for each state. .............................................. 83
5.4 Regulation of OPEX and CAPEX for DSOs ............................................................. 89
5.4.1 CAPEX regulation. ......................................................................................... 89
5.4.2 OPEX regulation. ........................................................................................... 90
5.5 Integration of DER into the market. ..................................................................... 90
5.5.1 DG ................................................................................................................. 90
5.5.2 Demand Response ........................................................................................ 92
6. Conclusions ............................................................................ 94
References .................................................................................... 98
XVI
Index of Figures
Figure 1: Simplified single line scheme of the electrical system. .......................................... 5
Figure 2: The product and service electricity model. ............................................................ 9
Figure 3: Concepts included in Costumers' bill. Source: Own .............................................. 9
Figure 4: Structure of the electrical market. Source: Own ................................................. 10
Figure 5: Offer and demand curve construction ................................................................ 12
Figure 6: Supply curve [2]. ................................................................................................... 12
Figure 7: Demand curve [2]. ................................................................................................ 13
Figure 8: Marginal Price [2]. ................................................................................................ 13
Figure 9: Marginal prices of the energy for each hour of a certain day [3]. ....................... 14
Figure 10: Daily and intra-day market sessions [1]. ............................................................ 15
Figure 11: Adjustment services markets. ............................................................................ 16
Figure 12: Volatility of prices in the wholesale market. ...................................................... 18
Figure 13: Capacity's evolution of the electrical system depending on the criterion ......... 23
Figure 14: Necessary components of Smart Grids and objectives. Source: Own .............. 25
Figure 15: Possible smart grids’ route integration. Source: Own. ...................................... 26
Figure 16: Levelized Energy Cost for different technologies [4] ......................................... 31
Figure 17: left net capacity curve / right monotonous capacity curve of transformer ...... 35
Figure 18: curves of the cogenerator .................................................................................. 36
Figure 19: curves of the transformer .................................................................................. 36
Figure 20: Thevenin equivalent at the connection point of DG .......................................... 39
Figure 21: voltage profile depending on the length and network conditions. .................. 41
Figure 22: representation of the extra-cost in the access tariff due to system services co-
ordination .................................................................................................................... 43
Figure 23: DER access and connection approaches. Source: [7]. ........................................ 47
Figure 24: Mechanisms of Demand-side Participation ...................................................... 55
Figure 25: Demand profile of the different groups. [8] ...................................................... 56
Figure 26: seasonal behavior of demand. Own based on data from ................................. 57
XVII
Figure 27: Dispersion of the generation and the demand [8]. ............................................ 58
Figure 28: Inelastic and elastic behavior of demand. ......................................................... 59
Figure 29: End-users' electricity bill. ................................................................................... 60
Figure 30: Possible distribution network topology and the monotonous demand curve for
the transformer during a year. .................................................................................... 71
Figure 31: Bids of firm capacity of DG producers connected to a certain area. ................. 72
Figure 33: Functioning of the firm capacity of demand market. ........................................ 74
Figure 34: Concept of System Service. ................................................................................ 83
Figure 35: Difference between the cost of producing energy with a certain technology and
the marginal price of the wholesale market according to its experience curve. ........ 91
XVIII
Index of Tables
Table 1: Characteristics of the different distribution networks [1] ...................................... 6
Table 2: Electrical activities involved in the electrical sector. ............................................. 20
Table 3: Support mechanisms according to different criteria [5] ....................................... 32
Table 4: Typical values for R/X relation for different voltage levels .................................. 39
Table 5: connection and access approaches. Source: Own ................................................ 45
Table 6: voltage levels and its typical generation technologies .......................................... 49
Table 7: Connection and access approaches. ..................................................................... 75
Table 8: System Services. Source: own and [7] ................................................................... 88
XIX
XX
1
1. Introduction, motivation and objectives.
1.1 Introduction and motivation
In Europe recently, the population awareness about the environmental impact together
with the high dependence of natural resources from geopolitical unstable countries, has
motivated changes in the European energy policy. For this reason, future intentions such
as the objectives 20/20/20 are motivating new tendencies in the energy systems of the
different European countries.
The effect of this policy on the electrical system, especially in Distribution networks, is
that EU countries have incentivized the connection to the network of small generation
groups close to the load (Distributed Generation). The consequences of DG can be
extremely positive for the efficiency of the electrical system. Additionally, if an
important share of the DG is renewable technologies, the environmental impact can be
dramatically diminished compare to systems entirely based in fossil fuel technologies.
Nevertheless, the effect of DG in those networks with high share of DG is becoming the
opposite of the desired. Due to the EU regulatory framework, DG:
Has priority access to the network, being able to inject power to the network
whenever they produce it without participating in the electrical markets. Therefore,
distribution network operators miss much information from the DG connected to
their network.
DG has no obligation to produce when the load peaks or when the system requires a
back-up (no firmness of DG). Therefore, distribution network operators cannot
consider DG when designing their networks in the long-term (planning).
The monitoring level of Medium and Low voltage distribution networks is deficient.
Moreover, DG has priority access and does not participate in the electrical markets.
All these factors make that DNOs have no information during the operation about
the actual state of the system.
The connection of DG produce changes in the operation conditions of the system
(Voltage variation, reverse power flows, etc.). Nonetheless, DG has no obligation to
support DNOs in the operation of the areas where DG is connected.
All these counterproductive factors make necessary changes in the current
regulatory framework, in order to about these problems and properly integrate DG
in the distribution system.
The traditional approach when expanding the distribution networks together with the
consumption habits of final customers, result in over-sized systems. The demand of
electricity is not constant along the time. It has peaks and valleys but the electrical
networks are designed to provide the required capacity when the load peaks. However,
these peaks represent a small proportion of hours over the total amount of hours in a
year. Consequently, the system is inefficient.
2
In order to avoid over-sized and inefficient distribution networks with high investments
in capacity, there is the need to change to a new paradigm. The new paradigm “demand
follows supply” in contracts with the traditional one “Supply follows demand” require
the implementation of the Demand-side participation.
The aim of the demand-side participation is to motivate the necessary changes in the
demand curve so that the capacity of the electrical system can be used more efficiently.
However, the current regulatory framework does not allow the actual participation of
the demand in the electrical market. It can be said that the demand is inelastic to
variations of the price. This is mainly due to the lack of information of final customers
about the real price of the electricity.
It is necessary changes in the regulatory framework to provide final customers with the
necessary information so that they can participate more actively in the electrical market.
Derived from this, the demand will manage more actively their consumption. This
active management will allow DNOs to use more efficient the already installed capacity
and assets.
Both, Distributed generation and Demand-side participation are two of the four
Distributed Energetic Resources (Distributed Generation, Demand-side Participation,
Decentralized Storage and Electric Vehicle) which constitute the Electrical Smart Grids.
The aim of the Smart Grids through the implementation of these four DER is to improve
the efficiency and sustainability of the system while reducing the environmental impact.
All this keeping the quality of the product and security of the service at the minimum
cost.
To conclude, Smart Grids are the evolution of the current electrical system. The success
of this evolution highly depends on the integration process of the Distributed Energetic
Resources. This integration process requires important changes in the present regulatory
framework and this is the motivation of this dissertation. Regulatory recommendations
based in a sustainable model constitute the basis for the already on-going integration of
the Smart Grids.
1.2 Objectives
The main objective of this dissertation is to create and define a proper regulatory
framework which integrates the Distributed Generation and Demand-side Participation.
This regulatory framework must protect the economic interests of all the agents involve
in the electrical system at the same time than ensuring the quality of the product and the
security and efficiency of the system.
In order to achieve this aim, it is necessary to accomplish a series of partial objectives
which constitute the basis of this main objective. These partial objectives are:
3
Define and characterize the Electrical Smart Grids.
Identify the key elements for the proper integration of the Distributed Generation
and Demand-side Participation.
Identify the role of the DSOs and barriers they face for the proper integration of
Distributed Generation and Demand-side Participation.
Analyse the regulatory and economic aspects that need to be modified for the
proper integration of Distributed Generation and Demand-side Participation.
The structure of the dissertation is as follows:
In the chapter 2, the four activities involved in the functioning of any electrical
sector that has suffered a de-regulation and unbundling process are described. These
activities are: the physical layer, technical management layer, economic activities
and regulation framework. In this chapter there is a special emphasis in the electrical
markets and the regulation of DSOs.
In recent years, due to the new tendencies of the energy policies in the EU, changes
in the energy systems are occurring. In the case of electrical system and especially
in distribution networks, the result has been the connection of a high share of RES
DG. However, the connection of the DG is the first step towards the connection of
other distributed energetic resources to the distribution networks. To face these new
challenges, the distribution networks must evolve towards the smart grids.
The development of the smart grids for the future integration of the distributed
energetic resources is crucial. Therefore, in chapter 3 the concept of smart grid and
certain characteristic associated to them are explained
Then, Chapter 4 analyses the current economic and regulatory barriers that
distributed generation and demand-side participation are facing for a proper
integration in the distribution networks. This analysis is divided into different parts
that have to be considered to properly integrate the distributed energetic resources in
the distribution networks: definition, market accessibility, planning, connection and
access, operation, information exchange, etc.
Subsequently, chapter 5 define possible regulatory solutions to the problems of each
DER diagnosed in chapter 4. Therefore, chapter 5 creates and defines a regulatory
framework which integrates the Distributed Generation and Demand-side
Participation. This regulatory framework must protect the economic interests of all
the agents involve in the electrical system at the same time than ensuring the quality
of the product and the security and efficiency of the system.
4
To conclude, in chapter 6 all the regulatory recommendations required to implement
the solutions presented in chapter 5 are summarised.
5
2. The current electrical system in Spain.
The electrical system has a complexity which goes beyond the physical layer, in fact,
the electrical system comprises four different layer: physical layer, technical
management, economic management and regulatory framework. Subsequently, a more
detail analysis about the four different layers that constitute the electrical sector, will set
the basis of how this industry runs.
The most important aspect in the current electrical sector was the liberalization process
that has taken place. In 1982, Chile was the first country which separated the different
activities of the electrical system into regulated and de-regulated activities. In the
following years, this trend extended to many other countries.
The liberalization process has different characteristics depending on the country.
However, all of these processes have in common:
Separation of regulated and de-regulated activities.
Creation of a wholesale market in which generators compete.
Access to third parties to the transmission networks through toll payments.
Freedom of clients to choose their energy suppliers.
2.1 Physical layer
The physical layer refers to the transformation of a primary energy into electricity and
the transmission of it to the final consumers through the electrical network. This layer
can be seen as the hardware of the electrical system.
A simplified single line scheme of the electrical system is depicted in Figure 1:
Figure 1: Simplified single line scheme of the electrical system.
6
The distribution network connects the transmission network with the final costumers.
The distribution networks can be divided into three different categories depending on
their voltage level:
High voltage networks (HV).
Medium voltage networks (MV).
Low voltage networks (LV).
The features of each category can differ from one country to another. However, the
general characteristics are presented in Table 1.
Type of
distribution
network
Topology Operation Number
clients
Amount of
equipment
Operation
flexibility
Monitoring
level
HV Meshed Meshed/
ring Few Several Medium High
MV Meshed/
ring Ring Several Many Few Medium
LV Meshed/
ring ring Many Many A few Low
Table 1: Characteristics of the different distribution networks [1]
High Voltage Distribution Networks
High voltage distribution networks present a meshed layout, which improves the
reliability of this level. Only few clients which demand high power requirements
connect to this network (for instance: industries, long distance trains and trains and
special regime).
The number of clients connected a type of network is a very important factor. The
higher number of clients the more difficult to monitor and operate the network.
Moreover, many clients connected demands high investments in facilities and
equipment.
Medium Voltage Distribution Networks
The typical topologies of medium voltage network are ring or meshed.The topology of
the medium voltage network depends on the geographical location of customers. The
meshed level is direct related to the level of service continuity that wants to be offered
to the costumers.
7
In the medium voltage networks DNOs have a medium monitoring level but not real
time operability. Typically, the SCADA systems responsible for the medium voltage
networks control only the substations which are located on the border (either with other
distributors or with high and low voltage distribution networks).
Typically, the SCADA systems can:
Monitor the measurements.
Maneuver.
Protection.
Visualization of equipment’ state.
However, at the moment DNOs only monitor the limits of the medium voltage networks.
Therefore, they cannot visualize the real-time conditions of this networks.
Low Voltage Distribution Networks
The low voltage network starts at the medium voltage substations and finishes at the
General Protection Box (GPB). Beyond this point, the network belongs to the clients.
The large amount of costumers and equipment connected to this network makes
unfeasible to set real-time measurements. The enormous amount of clients makes
necessary high installation and maintenance investments.
The monitoring level is deficient and this is why in most of the cases, when costumers
suffer blackouts, distributor are not aware of it. It is only through telephone calls from
the final clients that they realize there is a fault.
2.2 Technical management.
Technical management is the responsible for the proper functioning of the physical
layer. The technical management activity is carried out by the operators of the electrical
networks.
In distribution networks, the main responsibilities of distribution network operators are:
To keep electrical parameters of the system within the security limits (For instance:
voltage variation, temperature of active components, maximum current, etc.)
Maximize service continuity.
Maximize quality of the product for final customers.
Minimize system losses.
These responsibilities must be achieved by DNOs under any circumstances. These tasks,
as any other activity involving the DNOs, are defined and established by National
Regulatory Authorities.
8
Depending on the country, the operation of distribution networks can be performed by
different agents. In the concrete case of Spain, the distribution network is managed by
many distribution network operators such as (Endesa, Iberdrola, E.ÓN, Gas Natural
Fenosa, etc.) which are responsible for different parts of the system.
2.3 Economic management level.
The economic management refers to all the activities related to the purchasing and
selling of electricity. At this point it is very important to distinguish the electricity as a
product [MWh] and the electricity as a service [MW or MWh].
Electricity as Product (Energy)
Electricity as product (energy). The product electricity is manipulated by de-regulated
activities whose aim is to satisfy the energy needs of costumers.
The price of the electricity as a product can be fixed by different mechanisms. The best
of these mechanisms are the markets ruled by the offer and demand law. These markets
are the best mechanism because they ensure the balance between the interests of the
offer and the demand.
Electricity as a Service (Energy)
The electricity as a service (power or energy). The service of transmission, distribution
and delivering of the product is performed by the regulated activities. Their aim is to
guarantee the security and quality of the supply service.
Final customers pay for this service through the access tariff, which is the regulated part
of their bills. However, part of these services is ruled by the offer and demand markets.
This is the case of the adjustment services (technical constraints markets, ancillary
services, deviation generation-consumption) which are markets ruled by the offer and
demand law but used to ensure the security of supply when there are constraints in the
system.
The concepts of electricity as a product and electricity as a product are depicted in
Figure 2.
9
Figure 2: The product and service electricity model.
Due to the concept of electricity as a service and as a product, final costumers’ bill is
made up of two different parts: the energy consumption (electricity as a product) and the
electricity service. The price of the energy depends on the contracts between final
clients- energy suppliers or directly the price of the wholesale market.
In Figure 3, the breakdown of final customer’s electricity bill is presented:
Figure 3: Concepts included in Costumers' bill. Source: Own
Due to the unbundling process the regulated activities are not the same in all the country.
In all the cases, the regulated activities include investment and maintenance of the
Electricity bill
Network
(service) Regulated: access tariff
Energy
(product) De-regulated
( Energy market price signals)
Price signals
Market-reflective contracts
(ToU, CCP, Real-time pricing)
Regulated
Static prices
10
transmission and distribution network, but other concepts depend on the country. In the
specific case of Spain, the access tariff covers the cost shown in figure 2
2.3.1 Electricity markets
When describing the electricity as a product, it was claimed that the best mechanism to
fix the price for the electricity was the markets ruled by the offer and demand law. In
this section, the markets of the electrical system will be presented.
In all countries on which a process of liberalization took place, the structure of the
electrical market is structured as illustrated in Figure 4: Structure of the electrical
market.
Figure 4: Structure of the electrical market. Source: Own
2.3.1.1 Wholesale market
The wholesale market is where large amounts of energy are sold and purchased.
Through a series of market sessions, the generators and demand come to an agreement
about the amount and the prices of the energy that is going to be consumed each hour of
a certain day “D”. It is not until that day D that the electricity is actually delivered to
final customers.
The agents involved in the wholesale market are:
Electrical market
Wholesale market
(Generators↔Energy suppliers/Large customers)
Long-term market
Financial tools
(no physical delivery)
Short-term market
Intra-day market Adjusment Services
Markets Daily market
(physical delivery)
Retail market
(Energy suppliers↔Final customers)
11
Producers: they are the ones who generate the electricity (Nuclear power plants,
hydro power plants, etc.) and offer it in wholesale markets. They are the offer.
Large customers/ energy suppliers: they are the ones demanding the electricity in
the wholesale markets. Therefore, they are the demand.
The short-term markets within the wholesale market are sometimes characterized by the
volatility of its prices (spot market). This means that the prices of the energy are very
changeable along the time. This volatility involves economic risks, in terms of incomes,
for generators and large customers/ energy suppliers. Thus, both parts try to avoid this
risk using different economic tools. These economic tools can be established days,
months and even years in advance to the actual delivery of the electricity in day D
(long-term markets).
Therefore, the wholesale market is made up of: short-term and long-term markets.
A. Short-term markets
The short-term market comprises:
Daily market: economic activities that take place the day before the physical
delivery (D-1). In this market is where offer and demand purchase and sale the
energy for each hour of the day D.
In any market structure, the daily markets are there reference to establish the price
of the electricity. In all those countries where a liberalization of product related
activities, in order to operate and manage the daily market, there is a market
operator. However, there can be immature markets where there is no such market
operator.
The daily market works as follows:
In the daily market, generators and consumers send their offers and bids (energy
[MWh] and price [€/MWh]) to the market operator for each hour of the following
day (see left side of ¡Error! No se encuentra el origen de la referencia.). Besides
the offer and demand bids, the operator receives the international exchanges and in
the case of structured and mature electrical market, the market operator also
receives bilateral agreements (explained in long-term markets section).
As mention above, the supply and demand bids are for each single hour of the
following day; this means that there are 24 different products for each day.
After the market operator gathers the bids, the market operator places in ascending
price order the supply offers and in descending price order the bids offered by the
demand for each hour (see right side of Figure 5).
12
Figure 5: Offer and demand curve construction [2].
Controllable power controllable
Subsequently, the market operator creates the supply and demand curves as
represented in Figure 6 and Figure 7 respectively.
Figure 6: Supply curve [2].
13
Figure 7: Demand curve [2].
Finally, these two curves are overlapped and the point where the supply and
demand curve match, establishes the amount of energy [MWh] and the price
[€/MWh] for that energy that is going to be consumed for that hour (see Figure 8).
Figure 8: Marginal Price [2].
As mentioned above, this curve is done for each hour of the day so for the whole
day there are 24 different prices, as represented in Figure 9.
14
Figure 9: Marginal prices of the energy for each hour of a certain day [3].
Inspecting the supply curve it can be noticed that the curve starts at 0 €/MWh. This
is the energy that the nuclear power plants generate. The reason for this is that the
nuclear power plants are very stable and changing the working conditions is
difficult. In this way, they make sure that the energy produce by means of nuclear
power plants will be always in the pool. In contrast, some other technologies which
are more flexible on their operational status (cogeneration, renewable energies, etc.)
offer higher bids than nuclear power plants and other conventional technologies.
Furthermore, it is necessary to underline that all generators which are beyond the
matching, will not supply energy to the network. The offers are higher because their
operational costs are higher than the fixed price established in the wholesale market.
At this point is where the competence between generators plays and essential role.
In other words, those generators who offer the lowest prices are the ones that
provide the energy and receive the money. Conversely, if the cost of generating
electricity is higher than the pool price, it is not profitable to provide the energy and
those generators will not participate in the pool.
Changing the perspective to the demand side, the demand curve starts at 183
€/MWh. By law, this is the highest price that can be offered in the pool. This is
done because in this way, demand make sure that the vast majority of the energy
(around an 80%) they have to supply to the final clients will be provided.
In the specific case of Spain, the market operator is OMIE (responsible of the daily
market not only in Spain but also in Portugal). It guarantees a legal and transparent
administration of the daily market.
Intra-day market: those activities during the day of the physical delivery (D).
Once the daily market is closed, during day D offer and demand can change the
electricity they purchased/ sold in the daily market.
15
Once the daily market is closed and in the following 24 hours there are 6 intra-day
market sessions on which the generators and demand can change their deals about
purchase-sale (see Figure 10). The agents and market operator involve in this
market are the same as in the daily market and it works in a very similar way.
Due to its proximity in time to the actual delivery of the electricity, the volatility of
these markets is higher than the daily markets and that is why any agent tries to
avoid participating in these markets as much as possible.
Figure 10: Daily and intra-day market sessions [1].
This market is a consequence of the necessity to keep continuously the equilibrium
between generation and consumption. The consumption is foreseen by energy
suppliers, but this forecast may differ from the actual consumption. Therefore,
energy suppliers may need different energy requirement. These sessions help
generators and demand to manage the deviation from the actual consumption.
Sometimes it may occurs, as it happens in the daily markets, that the agreements of
the daily market are in conflict with the technical constrains of the system. These
conflicts are solved by the System Operator through adjustment services markets.
Adjustment services markets: additionally, during the day D there are other
markets which are used to ensure the security of the system and the equilibrium
between generation-demand. These markets are the adjustment services markets. These
markets include: technical constraints markets, ancillary services and deviation
generation-demand management.
16
Figure 11: Adjustment services markets.
Source: Own
Technical Constraints Management
The daily market is just based on offer and demand laws, economic laws. Nonetheless,
the electrical system has technical constrains and the most important, the electricity
does not follow economical laws but physical laws (Ohm and Kirchhoff).
The generation and the demand are scattered all around the national geography and they
are connected through the transmission and distribution networks. Therefore, there can
be technical constrains, for instance overload of lines and substations. Thus, some areas
of the electrical system might be congested affecting some of the generation plants that
were supposed to inject power.
To solve this problems, after each session of the daily and intra-day market and taking
into account bilateral agreements, the System Operator execute a process to manage the
technical constraints. For this purpose, the system operator analyses the scheduled
production of generation plants and expected international exchanges. With this
information the SO can operate the system to solve the constraints and guarantee the
supply of electricity.
Ancillary Services
As in the technical constrains study performed after the daily market, there is real-time
monitoring of the system. The Ancillary services are those tools necessary to ensure the
security, quality and reliability of the electricity supply service. Some of the ancillary
services are frequency-active power (primary, secondary and tertiary) regulation,
voltage variation-reactive power generation and others.
Adjustment services
Technical constraints
management
Ancillary Services
Frequency- Active Power regulation.
Voltage- Reactive Power regulation
Others.
Deviation generaton-deman management
17
Deviation Generation-Demand management
Additionally to all the mechanisms mentioned above, in order to solve the differences
that may appear minute to minute between supply and demand, the System Operator has
mechanisms to solve the deviations. Only in the exceptional case that the difference
between supply and demand is higher than a defined threshold, the System Operator can
convene a “deviation management market”. In this market, the SO can increase or
reduce the energy agreed in the daily and intra-day market.
These three services are normally controlled and operated by the System Operator. The
way to make the modifications is through markets on which these services are provided
to the SO by the generation groups.
A. Long-term markets and risk aversion
The long-term market (before D-1) includes all the economic activities which are
performed before the day of the physical delivery (before D-1).
When describing the short-term markets, it was mentioned that they are sometimes
characterized by the volatility of the prices. This volatility represents a risk in terms of
incomes for demand and generation. Therefore, in organised and mature markets it is
very common that the different agents establish bilateral agreements days, months and
even years in advance to the actual delivery of the electricity in the daily markets.
Therefore, when the agreements are created, there is not physical delivery of the
electricity (financial products related to the electricity).
The objectives of the long-term markets are:
1. Allow generation and demand to manage their economic risk.
2. Facilitate the development of retail market, increasing the competence on it.
These bilateral agreements are established directly between generators and large
customers/ energy suppliers. Thus, these contracts are not organised by any regulated
and centralised institution.
Some of the financial tools used to prevent the economic risk are:
SWAP: financial contract established a certain time “t” before day “T” where there
is the actual delivery and cash-flow. This contract determines the energy and the
price of this energy day T.
When day T comes, the energy is provided by the generator. The fixed priced of the
contract is compared with the price of the daily market. If the fixed price of the
contract is below the spot market price, demand pays the spot price market and
additionally gives the difference to the generator. Conversely, if the fixed price of
18
the contract is above the spot market price, the demand will pay the spot market
price but the generator will provide the difference. This cash-flow is depicted in
Figure 12.
Figure 12: Volatility of prices in the wholesale market.
Source: Own
Options: provide the owner the right, but not the obligation, to purchase or sell a
certain amount of asset (energy) at a specified strike price on or before a specified
date. The seller receives then a premium from the buyer [6].
There are two types of options: CALL and PUT. A CALL option is an option of
purchasing and a PUT option is an option of selling. In the moment the option is
established, the one acquiring the option pays a premium. The option can be
“exercise” (buy or sell the asset) by its owner at any time before the end of the
specified date. The cash-flow is equal to the difference of the strike price of the
asset and the premium already paid.
2.3.1.2 Retail market
The retail market is that one on which the energy suppliers sell the energy they bought
in the wholesale markets to final customers who do not participate in the wholesale
market.
Before the liberalization of the electrical sector, final customers could not choose their
energy supplier. The energy supplier was the same as the DNO controlling that area.
After the liberalization, final customers can choose the energy supplier which best suits
their needs.
The possibility of the final customers to choose their energy supplier motivates a fierce
competence between energy suppliers trying to attract new customers.
19
2.4 Regulatory framework
According to Tenenbaum, 1995, regulation is a “system (of laws and institution) that
enables a Government to formalize and institutionalize it compromises of protecting
consumers and investors in a certain industrial sector”
2.4.1 Structure of the electrical sector.
Due to the liberalization process, there are activities on the structure of the electrical
sector which are regulated while some other activities are de-regulated. The regulated
activities are network activities (transmission, distribution), technical operation and
organized market operation. The de-regulated activities are generation, wholesale
markets and retail markets and they are ruled by the offer and demand law.
A perfect comprehension of the structure of the electrical sector is critical to fully
understand the regulatory framework. In Table 2, there is a schema comprising all the
activities involved in the electrical sector. In yellow the regulated activities and in green
de-regulated activities.
The network activities (distribution and transmission) are considered as natural
monopolies. This is because there is no sense in constructing new lines in parallel to
allow the competence between different companies. Therefore, distribution is a
regulated activity. There are two main aspects within the regulation of the distribution
activity: Cost based or incentives based regulation and the control of the quality of the
service.
2.4.2 Regulation of the distribution activity
There are two ways to regulate the distribution activity: Cost of service and regulation
through incentives.
Cost of Service has been the traditional regulation method for natural monopolies in the
electrical sector. According to this method, the National Regulatory Authorities (NRA)
establishes the remuneration for the company according to justified costs plus the return
on the invested capital (ROI).
The main problem with this regulation is that the companies do not have any motivation
to reduce costs and make more efficient their networks. To solve this problem, there is
another type of regulation, incentives based regulation.
Incentives based regulation. The NRA fixes a defined amount of money for a certain
period of time (4 or 5 year). With this method, DNOs try to minimize their costs in
order to obtain higher revenues.
When the period of time finishes the NRA supervise the cots and investments. The
result of this supervision is a new formula that limits the prices or the incomes of the
company.
20
The main problem with this method is that together with the reduction of costs, DNOs
may incur into less quality service. For this reason, NRA must control and define a
minimum quality for supply service.
Activities within the electrical sector
Generation Network Transactions
Ordinary regime: all the
classical generation
technologies.
Special regime:
All the technologies
which have less
environmental impact or
better energetic
efficiency.
Adjusment services.
Transmission
Expansion planning
Construction
Maintenance
planning
Maintenance
Transmission
operation
Distribution
Expansion planning
Construction
Maintenance
planning
Maintenance
Distribution
operation
Wholesale market
Retail market
Energy suppliers
Complementary
activities
Settlement.
Billing.
Metering.
Coordination
Technical operation of the electrical system
Organized market operation ( if it exists)
Table 2: Electrical activities involved in the electrical sector.
Source: own
2.4.3 Quality of service, Security and Efficiency.
Another important factor within the regulation of the distribution activity is that NRAs
keep the control of the three main tasks of DNOs:
Good service quality: maintain voltage and frequency within acceptable values.
Security: continuity of the service in the short-term scale.
Efficiency: electricity supply with the minimum cost.
There are different measures to keep control of these factors and although they may
vary from one country to another, in all the country these three aspects are regulated.
21
3. The evolution of the current electrical system: Smart
Grids. 3.1 Reasons for the change of the current electrical system.
In recent years there are three main factors that are determining the energy policy in
Europe. These three factors are:
Reduction of environmental impact.
Improve security of raw materials supply.
Sustainability of the power systems.
This is why in order to lessen the environmental impact and fossil fuel dependence, in
2008 Europe decided to set new milestones in its energy policy for 2020. The attempt
gave as a result the objectives referred to as 20/20/20 for 2020:
Reduction of greenhouse gases emissions by 20% of those in 1990.
A 20% of the total energy consumption produced with renewable energies.
Reduction of 20% of the total energy consumption enhancing the energetic
efficiency.
Environmental Impact
In recent years society has witnessed a consciousness-raising about the environmental
impact and the crucial role that human activities play on it.
The environmental impact is due to the gas emissions originated in factories, vehicles,
fossil fuel power plants, etc.
Some of these gases only affect to the local environments (gases such as NOx and SOx),
however the emissions of CO2 affect to the global greenhouse effect. The CO2 is one of
the gasses that appear in the exhaust of the combustion of fossil fuels.
Fossil fuels are currently indispensable in human activities such as industry and
transportation. The main problem with CO2 is that it is released to the atmosphere in
higher amounts that what can be naturally.
The awareness about this problem resulted in a search of alternative energy sources that
pollute less than fossil fuels. The consequence is the development of renewable energies.
Renewable energies enclose all those technologies which use local resources which are
virtually inexhaustible. Nevertheless, the renewable energies are characterized by their
intermittent and unpredictable nature (the wind blows when it wants and the sun
shines when it wants). These characteristics introduce new and big challenges in the
electric system because unlike conventional generation plants, renewable energies are
non-controllable technologies.
22
Security of Supply
Regarding the security of supply, fossil fuels constitute the basis for European
energetic system. Most of these fossil fuels are imported from countries outside Europe
with unstable political background, decreasing European energetic independence. Thus,
it is a must for Europe to find alternative energy sources to be more independent from
exterior energy supplies and improve its security of supply.
Due to this dependence, Europe has to introduce changes in its energy policy in order to
use more efficiently its own resources while it shifts from fossil fuels to other forms of
energy which reduce its external dependence. With the aim of contributing to the
reduction of fossil fuel dependence, the electrification of the transportation can be the
perfect option.
Nonetheless, the current electrical system is not prepared for the integration of electric
vehicles. Still, there is the need to improve the technology but also to define the proper
regulatory background for their future integration in the electrical system.
Sustainability of the electrical system
Regarding the electrical system, the objective of reducing 20% of the total consumption
improving the efficiency is inherently linked with its sustainability. This reduction of
the energy consumption cannot only be based in a reduction of each final customer of
their consumption. Europe must be able to reduce the energy consumption developing
more efficient electrical system which improves the utilization of the electricity.
For instance, In Figure 13 the evolution of networks’ capacity is depicted. The traditional
method used to supply the growing demand has been increasing the capacity of the
system. The method is based on the idea that the electrical system must be able to
supply energy in the worst case that all consumers, at the same time, require the
maximum power contracted.
The result of this conception is that systems are designed for a capacity which is only
used few hours a year. Therefore, the electrical systems in most of the cases are over-
sized systems. This situation is unsustainable because large investments are required to
provide that capacity which only few hours along the years.
In the past (left part of figure 1), conventional generation released its energy to the
transmission network and all based on a centralized control (System Operator). The
transmission network was connected to the distribution network with a passive control.
23
However, there was a time when distributed generation started to be connected to the
distribution network.
Figure 13: Capacity's evolution of the electrical system depending on the criterion
Currently (central part of figure 2), the problem that the electrical system is facing is
that distributed generation has a very strong presence on distribution networks.
However, this distributed generation is connected to the distribution network as an
intermittent generation (lacks of security of supply and firmness). Hence, distributed
generation is substituting to the conventional generation in energy [MWh], but not
capacity [Mw].
Subsequently, the installation of every MW of distributed generation involves another
MW of conventional generation, in order to maintain security of supply. This situation it
is unsustainable and that is the reason why a different perspective needs to be taken to
address this situation more efficiently.
Distributed generation needs to be properly integrated in the network. Furthermore,
demand side participation has a very important role to achieve the active management
of the network (right part of figure 1). On top of that, the efficiency of the overall
system requires bidirectional communication between transmission and distribution
network operators. Only changes on this direction can reinforce the efficiency of the
system.
24
The problems of the electrical system demonstrate that if the electrical system wants to
play an important role in the reach of the three main objectives, new solutions are to be
considered.
The integration of new technologies that help to achieve the 20/20/20 objectives is a
process which in many countries has been called as “Smart grids”. The smart grids will
represent the evolution towards a more efficient, secure and environmental friendly
system. This evolution will improve the quality of the product (electricity) and the
efficiency and sustainability of the service.
3.2 Concept of Smart Grids
Smart grids are those electric networks that enable the integration of the Distributed
Energetic Resources (DER) in an efficient way, maximizing the quality of the service at
the minimum cost.
The DERs are:
1. Distributed Generation (GD).
2. Demand side participation.
3. Electric vehicle.
4. Decentralized storage.
It is crucial to comprehend that smart grids are neither something physical (no smart
meters, no TICs, no new topologies on the networks, etc.) nor a revolution or
completely new system that discards the present one.
The smart grids are a process, an evolution of the current electric system that will
enable the integration of the DER enhancing the quality, efficiency and
sustainability of the electrical service and product.
The success of this process compels the proper technological development and the
convenient regulatory framework. Both of them are fundamental for a convenient
integration of the DER and therefore, the proper implementation of the smart grids
process.
The NRAs through regulation have to ensure:
Protection of the interest of all the agents involve in the electric system.
To ensure the security, efficiency and quality of the electricity service and
product.
25
To set the proper policies to facilitate the development and maturity that new
technologies becoming profitable and therefore competitive enough to be integrated into
the electrical markets.
The different DERs that constitute the smart grids, together with the complementary
elements (new technologies and regulatory framework) and the objectives, are depicted
in Figure 14.
Figure 14: Necessary components of Smart Grids and objectives. Source: Own
Since the smart grids are an evolution, they need to introduce step by step each of DER.
Each DER requires first the integration of other DER, new technologies and adequate
regulatory rules to be successfully integrated into the system.
As a consequence and as any other process, the smart grids require several steps to be
integrated within the system. A possible route could be as represented in Figure 15.
26
Figure 15: Possible smart grids’ route integration. Source: Own.
Presently, distribution networks are functioning in very good conditions but DNOs need
a much higher level of monitoring and operability of their medium and low voltage
networks. DNOs receive scarce real-time data from these networks what means that
they are unable to supervise their actual state. Other requirements such us more remote
management systems, more tools to help the operation of the grids and better regulatory
frameworks are indispensable to achieve the optimum working condition of distribution
networks.
In parallel the evolution towards integration of DG is occurring. The main problems
about the integration of the DG is that there is no the proper background to incentivize
DNOs to integrate DG in their networks.
Subsequently, the expansion of remote management systems (smart meter among others)
with bidirectional communication will be the technological gateway to integrate the
following DERs.
Afterwards and not earlier, the demand-side participation will be possible. The demand-
side participation, involves demand-side management and demand response.
Additionally, the introduction of electric vehicles will require more advanced
technologies and it will play an important role within the demand-side participation. Of
course, all these changes must be accompanied by adequate regulatory rules.
Finally and after all these steps, the optimization and the coordination of all DERs
integrated within the system must be performed. It is only after completing this route,
when the electrical system will be provided with benefits such as:
27
Self-regenerative: networks will be provided with components able to check,
analyse and diagnose in order that they can identify and fix those devices which are
damaged or in bad operative conditions. As a consequence, the quality of the
supply will increase.
System focus on consumers: consumer will be well aware of their consumption
and prices and based on this, they can modify their habits. This change will help to
the reduction of electricity utilization in peak hours, when the prices of the
electricity are higher. At the same time, it would be possible to shift part of the
demand of the peak hours to the valley hours, obtaining a more stable demand
curve.
Quality improvement of the service: consumers will be able to choose the quality
they need attending to different prices. Moreover, the use of signal actuators based
on power electronics will prevent perturbations (harmonics and flickers) from
equipment.
Facilitate interaction between agents in the electrical markets through a secure
network that allows the aggrupation of many costumers and distributed generation,
facilitating their aggregation and communication. The interaction between offer and
demand side is crucial to achieve resource’s efficiency because there will be a
better agreement in terms of capacity and energy available at any moment.
Optimized use of facilities and their operation: due to the information that clients
have, the consumption will be more equilibrated along the day and the utilization of
the network will be better. This motivates a flatter demand curve, allowing better
designs of the network, resulting in fewer costs.
All these characteristics can be understood as a more efficient and sustainable system
with a better quality of electricity product and a superior electricity service.
In next chapter, DG and Demand-Side Participation are described. Also an analysis
about the technological and regulatory issues affecting each of them is carried out. This
dissertation focuses on these two DERs due to their proximity in time and already on-
going process of DG integration.
The integration of the other two DERs (electric vehicle and decentralized storage) are
further in time but many of the conclusions of this dissertation can be used for their
future integration.
In next chapter, DG and Demand-Side Participation are described. Also an analysis
about the technological and regulatory issues affecting each of them is carried out. This
28
dissertation focuses on these two DERs due to their proximity in time and already on-
going process of DG integration.
The integration of the other two DERs (electric vehicle and decentralized storage) are
further in time but many of the conclusions of this dissertation can be used for their
future integration.
29
4. Distributed Energetic Resources (DER). 4.1 Distributed Generation (DG).
4.1.1 Definitions.
Distributed generation (DG) refers to electric generation systems connected to the
distribution network, which are characterized by their low power and their near
location to the load or consumption.
These three characteristics are very important because not every generation unit
connected to the distribution network is DG. DG must be of small size and it has to be
close to the consumption, providing with benefits to the system which are going to be
explained in next sections.
Apart from this conceptual definition of DG, in the different European countries there
are two other concepts that are related to DG but represent different things.
One of them is a normative concept. This concept gathers all those technologies whose
capacity is below a certain level, established by law (different in each country). The
technologies covered by this normative concept present different incentives trying to
make them economically efficient. For instance, in Spain this normative concept is
referred to as “Special Regime” and it includes technologies whose capacity is lower
than 50 MW.
The other important concept is the Renewable Energy Sources (RES). Renewable
energies include all those energy sources which are obtained from natural resources
virtually unlimited (either because they exist in enormous quantities or because they
regenerate by natural processes faster than they are consumed by human activity).
According to this definition, these renewable energies are: wind, solar, geothermal,
wave, tidal, hydropower, biomass, landfill gas, sewage treatment plant gas, biogases, etc.
Some of these technologies such as wind and solar are account for an important share of
the DG technologies.
When determining whether a technology is renewable or not, it is crucial to consider the
whole life cycle of the equipment deployed to produce energy with that technology. The
whole life cycle involves: manufacturing, transportation to the installing point,
installation, energetic production cycle and recycling of the equipment. The
environmental impact during the whole life cycle must be reduced as much as possible
while producing during the energetic production cycle more that the energy used in the
rest of the life cycle of the equipment.
These three concepts (DG, normative concept and RES) can be easily mistaken and it is
important to understand how each concept relates to each other.
DG ↔ Normative concept
30
All DG is covered by the normative concept: distributed generation technologies
are clustered in groups so that their total capacity is under the limit defined by the
normative concept.
DG ↔ RES
Not all DG is RES: DG comprises other technologies which are not renewable
(cogeneration, internal combustion engines, steam turbines, micro-turbines, etc.).
Not all RES is DG: a wind power farm which comprises several windmills
producing 200MW connected to the transmission network, is not DG.
Normative concept ↔ RES
The normative concept does not only includes RES: SR comprises other
technologies which are not renewable and whose capacity is under the regulatory
limits (cogeneration, internal combustion engines, steam turbines, micro-turbines,
etc.).
All RES are the normative concept: all renewable technologies are gathered so that
their capacity does not exceed the limits, being within the normative concept and
obtaining incentives.
4.1.2 Market accessibility
4.1.2.1 Costs of technologies deployed in DG.
The main target of this section is to determine the cost of producing each MWh with
different technologies deployed in DG. The lower this cost, the more competitive they
are and vice versa.
The characteristics of each technology can be very heterogeneous (capacity, efficiency,
utilization factor, investments and operation costs, etc.), especially when comparing
technologies which use different sources, making necessary to establish a measure that
allows the comparison. The measure used is the “Levelised Energy Cost”.
NREL defines the Levelized Energy Cost as:
Levelized Energy Cost (LEC) is the price at which electricity must be generated from a
specific source to break even over the lifetime of the project. It is an economic
assessment of the cost of the energy-generating system including all the costs over its
lifetime: initial investment, operations and maintenance, cost of fuel, cost of capital, and
is very useful in calculating the costs of generation from different sources [Referencial a
NREL website].
Therefore, to compare the competence of the different technologies it is necessary to
compare the LEC of each technology. In Figure 16, there is such comparison.
31
Figure 16: Levelized Energy Cost for different technologies [4]
From Figure 16 it can be concluded that:
Conventional technologies (Nuclear power plants, Coal power plants and
combined cycles, hydropower) have a very low LEC mainly due to their
technological development and maturity.
Newer technologies (Biopower, geothermal systems, offshore wind power) have
higher LEC but not so distant from those of the conventional technologies.
Onshore wind power is a recent technology which has experimented a rapidly
development in recent years. Due to the efforts deployed in this technology, the
LEC are comparable to those of the conventional technology. However, the main
drawback of this technology is its intermittent and unpredictable nature.
Solar technologies (Solar photovoltaic and concentrating solar power) bear by far
the highest LEC of all the technologies represented in Figure 16. This means that
presently is not a competitive technology requiring more technological
development.
4.1.2.2 Priority access and support mechanisms for the integration of
renewable energy technologies.
32
In order to compensate the differences in cost between RES and conventional
technologies, most of European countries in recent years have developed new energetic
policies incentivizing the integration of RES. In Europe, this integration has been
facilitated using two elements: priority access and support mechanisms.
Priority access: the European Directive established that RES must be provided with
permanent access to the grids, what means that they can inject electricity when they
want. The priority access is used with the objective of incentivizing the energy supply
from renewable energies.
Additionally, in most of European countries support mechanisms to incentivize the
integration of RES have been created. The support mechanisms can be classified
according to two criteria:
If the regulatory actions intervene on the price or the quantity of generated power
or energy.
If regulatory actions affect the initial investment or the electricity generation
stage.
Combining these two criteria, there are four different possibilities:
Regulated prices Regulated quantity
Based on initial
investment
Investment grants
Tax relief Auctions
Based on
generation stage Regulated tariffs (FIT) Fee+ Green Certificates
Table 3: Support mechanisms according to different criteria [5]
In Europe, the two mechanisms used are the feed-in tariffs (FIT) and the green
certificates. Therefore, only these two mechanisms are analysed in this section.
a) Feed-in tariffs: RES producers have the right to sell all their production whose
price is fixed by regulatory authorities. The price can be fixed for the whole production
(total regulated tariff) or partially fixed (a regulated incentive that is added to the
marginal price of a KWh in the wholesale market).
This prices or incentives are fixed and they are differently for each renewable
technology (wind power, photovoltaic, biomass, etc.). This is because this tariff tries to
take into account the maturity of each technology.
Another important aspect of this tariff is that the fixed price or incentive can be the
same over the time or variable. In those cases where feed-in tariffs vary over the time, it
is important to define the conditions of these variations to provide clarity for investors.
33
b) Fees and Green Certificates: This mechanism legally impose on consumers,
suppliers or generators, depending on the cases, that a certain percentage (which
typically increases along with the time) of their electricity supply or production must be
generated by RES.
After finishing each established period (normally a year), the agents obligated by the
legal imposition, must provide a certification to the National Regulatory Authority to
show that they have accomplished the established amount of green certificates. A green
certificate is equal to a MWh generated by RES.
The Green Certificates are previously provided by the National Regulatory Authority to
RES generators. The green certificates have fixed prices, so this mechanism is
technically neutral. They boost the development of the most competitive technologies,
undermining the development of new renewable technologies. To avoid this, sometimes
some modifications are made to take in account the different technologies.
Whit this mechanism, generators cases obtain benefits for selling commodities in two
different markets. One due to the electricity sold in the wholesale market and the other,
due to the green certificates.
4.1.2.3 Objective of subsidies for new technologies.
Due to this grants, RES have witnessed an important growth within the share of the total
energy production. Nevertheless, the results of these incentives in many cases did not
have the desired aims.
These energetic policies have resulted in the integration of an excessive share of
immature technologies into the system. This immaturity causes new problems to DNOs
during the planning and operation of the distribution networks. Therefore, DNOs have
to face new challenges if they want to meet their obligations, to keep the quality,
security and efficiency of the distribution networks.
The aim of any proper system of incentives has to be the gradual technological
development so that immature technology become more competitive, being able to
reduce their costs below the marginal price of the wholesale market. In this way, they
can compete against other technologies and take advantage of economies of scale.
Because of this, when regulators develop grants for new technologies they have to
consider two important factors:
Technological maturity: the stage of the technology that is going to be subsidised.
Penetration of each technology: share of the total energy that each technology
accounts for.
Regulatory authorities must consider these two factors, because the implementation of a
high share of immature and non-competitive technologies can result in:
34
Operation and planning problems for DSOs.
Increase of electricity price, due to the introduction of technologies with grants that
represent an extra cost on the final price of electricity.
4.1.3 Planning
Planning refers to the long-term decisions that the DNOs have to make in order to
provide enough capacity (generation) for the expected future demand (around 15 years
ahead), under secure conditions, considering quality of supply requirements and trying
to minimize the costs. Hence, DNOs invest on those assets that allow the supply of the
future demand with the minimum cost.
Traditionally, the growth of the demand was easily predicted by DNOs. Nevertheless, in
recent years the recent connection of DG in the distribution network makes more
difficult for DNOs to predict the behaviour of the future grids. DG supposes a big
change on the traditional passive approach of the distribution step, because not only
demand is connected to the distribution network but also generation.
The effects of DG on the distribution network can be very positive if it fulfils the three
main characteristics presented in DG concept in section 4.1.1. Since distributed
generation is small and located next to the load, part of the energy coming from the
higher voltage levels is not necessary. This reduces the electrical losses of the system.
Additionally, due to the reduction of power flows coming from higher voltage levels,
DNOs can postpone the investment needed to reinforce the network and supply the
growing capacity demand. These investments could be postponed until the moment that
DG would not be the optimal solution.
Furthermore, most of the technologies deployed in DG are renewable energies (Wind
power, solar-photovoltaic, etc.) or technologies with much higher efficiency
(Cogeneration for instance) than conventional technologies. As these technologies
substitute conventional ones, the environmental impact of the electric system will be
alleviated.
Nonetheless, the actual scenario that DNOs face presently on those networks with high
share of DG is totally different due to two main reasons.
First, the different governments around Europe have incentivized the implementation of
these new technologies by providing them with priority of access contracts. This
means that in most cases, they can generate when they want and as much as they want
without considering the local demand-supply equilibrium. As a result of this policy, the
effects of DG in the electric system are the opposite of the ones abovementioned:
Higher electrical losses.
More reinforcement of existing assets.
Risk for security of supply service.
35
The second important factor is the firmness of DG. The firmness is defined as the
availability of a generator to produce when the system faces peaks of demand or there is
a lack of generation. In other words, firmness is capacity of a generator to produce when
it is required.
The main problem that DNOs presently face is that DG that is being connected lacks of
firmness. For this reason is that DNOs to ensure the security of the system, install a
megawatt of conventional generation for each megawatt of DG. Therefore, DG is
replacing conventional generation on energy but not on capacity, resulting in oversized
and underutilized systems.
In order to show how the firmness of DG influences the DNOs in the planning step, the
following example is presented:
In Figure 17: left net capacity curve / right monotonous capacity curve of transformer,
the annual net and the monotonous curve of a transformer 132/45 kV 30MVA are
represented.
Figure 17: left net capacity curve / right monotonous capacity curve of transformer
From the net curve (includes the inverse generation), the maximum power that the
transformer supplies is 28MW, hence the transformer is not overloaded.
This transformer has a cogeneration group within its grid with the following annual
production curves:
36
Figure 18: curves of the cogenerator
The cogeneration supply curve is predictable, stable, regular and it behaved more or less
according to the demand habits (it decreases it production during weekends, August,
eastern and Christmas). The maximum power output is roughly 12 MW.
In the gross curve of the transformer depicted (Figure 19):
Figure 19: curves of the transformer
It can be seen that if conventional generation and the capacity of the cogeneration
group are used, the transformer is overload. So at this point, the following question
arises: Can the DNO rely on the firmness of this generator and stop using the
proportional part of conventional generation? The current answer is no, the DNO
cannot rely on the firmness of the cogeneration group. Therefore, in this particular case,
the DNO in order to solve the overloading issue integrated a second transformer
(reinforcement) to decrease the overload of the original one.
37
This example can be extrapolated to many other cases on which if a proper regulatory
framework existed, the DNO could postpone its investment and reduce the power
coming from conventional generation. But the uncertainty about the DG leads DNOs to
invest earlier that they would do if this cogeneration group did not exist.
For this reason is necessary to create contracts which incentive firm DG.
Firm DG production contracts.
Firmness of DG refers to the capacity of a generator to produce when it is necessary for
distribution system (normally, when load peaks).
Firm contracts are a type of access contract which incentivizes the installation of firm
DG. Because of this contract, .DNOs can obtain benefits in the planning and operation
step:
Operation: DNOs knows more precisely which capacity they can rely on.
Planning: DNOs can analyse more accurately the DG capacity installed and the
necessary future DG or network investments. Subsequently, they can foresee when the
DG curtailments are less cost-effective than new reinforcements.
The way to incentivize this type of contracts is further analysed in chapter 5.
4.1.4 Operation
Operation refers to the short-term decisions that the DNOs make in order to ensure the
security and quality of supply in the near future (1 year ahead to real-time operation).
Traditionally, the operation of the distribution networks is characterized for:
Being passive: the demand is easily predicted by DNOs.
Low monitoring level: due to a very predictable load, there was no need to
supervise what is happening in real-time, especially on the medium and low voltage
grids.
Network topologies and designs based on unidirectional power flows from
transmission grids to the end-users.
Now, due to the connection of the DG to the distribution network this task has
complicated significantly. The current way of connecting DG to the grid, introduces
bidirectional power flows and continuous variations on the functioning of the system.
The distribution grids are not network any more, they are systems which require the
DNOs to create monitoring tools and implement ICTs to supervise the real-time or close
to real-time operation of the system.
Effects of DG on distribution systems
The connection of DG to the distribution system introduces three main challenges for
the operation of the system:
38
Local power quality due to voltage variations, fault levels and system
perturbations such as harmonics and flickers.
Growing local congestion due to higher local generation than demand, resulting in
supply interruptions.
Longer restoration times after faults on the network.
Remarkably important on the operation of grids with high share of DG are the voltage
variation and congestions. The two main drivers used by DNOs to monitor these
problems are:
Voltage: threshold values that determine the maximum and the minimum limits of
the voltage, define the secure area on which the system can be operated under
secure conditions.
Current: the most important factor that limits power flow in a system is the
thermal limit of the active elements (components through which current is
circulating, for instance: electrical lines and equipment).
But the heat is strongly related with the current. Due to Joule’s effect (P=I2·R), when the
current circulates through the system it produces heat. Hence, current must be
maintained under certain boundaries if thermal limits do not want to be surpassed.
In other words; controlling the current, power flow and heat are subsequently restricted.
As mentioned above, the DG can force the distribution system beyond the secure region
due to voltage variation or/and congestions.
Voltage variation
The voltage control in electrical networks is essential because the good functioning of
all equipment connected to the network depends on the correct voltage profile. Thus, the
voltage is a fundamental parameter for DNOs to measure the quality of the service and
the product delivered to the final clients.
The connection of DG produces voltage variation. These voltage variations are due to
DG’s injection of active power in the MV and LV levels and also due to reverse power
flows.
a) Injection of active power: the injection of active power of DG on the
distribution networks leads to voltage profile modification. Overvoltage on the
connection points of DG is the most common problem.
In order to solve this issue, voltage-reactive control is one of the most important
system services for DNOs and generators. The objective of this service is:
o To keep voltage values close to the rated voltage (To avoid voltage variation).
o To optimize the reactive power flows through the network.
39
At the moment, DNOs control the voltage profile using the following components:
o Generators: elements which participate actively on voltage control and provide with
a dynamic voltage control.
o Passive compensation/ Condenser and inductance: elements which participate
actively on voltage control and provide with a static but not dynamic voltage
control.
o Electric lines: they consume and produce reactive power depending on their
functioning state.
o Transformers: components which participate actively on voltage control.
In order to carry out a proper voltage control, DNOs need to understand how DG affects
to the voltage profile. To comprehend such influence, the scheme represented on Figure
20 will be considered. The grid is represented by its Thevenin equivalent (Vr, R, X) and
the generator is represented as an active and reactive power injection.
Figure 20: Thevenin equivalent at the connection point of DG [6].
According to [6] the relation between the injected active and reactive power and the
voltage on the connection point are strongly related by the parameter k= (R/X).
This parameter is next to zero for very high voltage levels and its value is significant for
MV and LV grids. Typical values are represented in Table 4.
Table 4: Typical values for R/X relation for different voltage levels [6].
One of the results of [6] is that the lower the value of parameter k=(R/X), the less
influence the active power has on voltage control. Conversely, the higher the value of
the parameter k=(R/X), the more important the effect of active power on voltage control.
40
DG injects active and reactive power, but from the previous result, it can be concluded
that the active power is the main driver of voltage variations for the DG connected to
MV and LV (high value of k). This provokes that due to the active power injected by
DG on the connection point, the voltage in that point increases. This negative effect of
DG in MV and LV networks must be compensated through reactive power absorption
to maintain voltage levels within the specified values predetermined in absence of DG.
For HV distribution networks, the parameter k is not so significant. Hence, the reactive
power is more important than the active power injected by DG on this voltage level.
The operation of HV grids is more similar to the one on transmission networks and
power-frequency tools are used. Nevertheless, HV networks are out of the scope of this
section because the vast majority of DG is expected to be connected to the MV and LV
grids.
Furthermore, in [6] is conclude that the higher the parameter k=(R/X), the less influence
the reactive power has in voltage variation. Because of this, to compensate a certain
voltage variation motivated by a certain amount of active power, a higher amount of
reactive power needs to be absorbed. Hence, the voltage control of DG in MV and LV
grids absorbing reactive power is not effective, because much more capacity would be
necessary, being in some cases the required reactive power twice the installed active
power capacity.
As a result, it is necessary to incentivize DNOs to install reactive power compensation
to guarantee quality of supply at the same time that installing new DG. These
investments could be for instance on:
Passive compensation installation (condensers and reactances).
On-load tap changers transformers.
Centralized voltage control system.
Notwithstanding these investments, the best solution is to encourage innovation so that
new technological solutions to this problem can be found.
b) Reverse power flow: reverse power flows may occur when the local DG
production exceeds local demand. The more local generation surpass local demand, the
worse the impact because the voltage profiles of the final consumer will be worse and
thereby, the quality of the service and the product will worsen.
In Figure 21 the reverse power flow effect is depicted. The tap-changer transformer
keeps a certain voltage value where it is connected. The voltage drops along the
network. If the feed-in of the DG downwards the transformer is higher than the burden,
the voltage in that transformer rises. The problem comes when the voltage variation is
41
higher than a certain value. The tap-changer transformer cannot compensate the voltage
profile next to the load.
In Figure 21 the voltage variation in the load transformer in represented for four
different situations.
Figure 21: voltage profile depending on the length and network conditions. [7]
Congestions
There can be congestions in the network when the DG force the system beyond its
capacity limits (PG-PL>Pmax). These congestions may lead to emergency situations
where interruptions in supply might be necessary to ensure the security of the system.
Moreover, there can be situations when there is an excessive demand (PL -PG >Pmax)
leading to outages. These situations may occur in the future when the electricity vector
becomes even more essential and high loads such us electric vehicles, heat pumps and
heating ventilation and air-conditioning (HVAC) become a reality.
Solution for congestions: State system operation
The above mentioned instability situations are becoming more and more frequent in
those grids with high share of DG. In the near future, these situations are expected to
appear more often depending on:
Type of technology use in DG (especially intermittent technologies).
Their geographical location: DG located in inconvenient points of the system.
Their voltage level of connection.
42
To solve these problems it is necessary to create a field where the DSOs can
communicate with DG and suppliers/ large customers and benefit from their flexibility.
This field should be supervised by the DSOs and it will allow them to influence the
demand4 and the generation when the constraints of the system are surpassed. The best
method to organize and manage this field is through a market mechanism, where offer
and demand can send their bids and purchases.
The functioning of this distribution market would be as follows:
The DSO would receive the demand curve one day in advance from the national
energy market (dairy and intraday markets). Based on the expected demand, DSOs are
able to analyse whether the agreements of the energy market result in local congestion
in some area of the distribution system (the agreements of the national market do not
always match with the local constraints of the network). Therefore, this market referred
to as distribution market, will behave differently depending on the state of the system.
Three different possible states in the system are:
1) Normal State: The demand curve does not violate any constraint of the distribution
system and the system will function smoothly.
2) Alert State: Because of the demand curve agreed in the national energy market,
there can appear local congestions in the distribution system, endangering the
security of part of the system. Generation and demand flexibility are used in these
situations.
3) Emergency State: when the congestions cannot be solved using the flexibility of the
DG and the demand during the alert state or other types of severe faults which
affect an important part of the system occur.
Although, DG is connected to the distribution network, it would participate in the
national energy market as any other producer. The figure of an aggregator of DG could
help DG to compete against larger power plants.
This distribution market would represent an extra cost in the electricity price. This extra
cost is the same as other services already included in the final product price and
provided by the TSO and the system operator. Figure 22: representation of the extra-cost in
the access tariff due to system services co-ordination. represents the price of the electricity as a
product and the extra costs due to the services provided by DSOs and TSOs.
4 Influencing the demand is the objective of demand-side management (DSM), included
within the concept of demand-side participation (DSP). This is analysed in section 4.2.
43
Figure 22: representation of the extra-cost in the access tariff due to system services co-ordination.
Source: Own
Normal State
In the normal state, the distribution network runs smoothly. The DSOs act as operators,
supervising the security and quality of the supply service. This task is performed by
monitoring in real-time the conditions of the distribution network.
When the system is in normal state, the distribution market is not operating. The
distribution market is just a system service to help DSOs to coordinate and control the
balance between generation and demand, ensuring the quality of the service and using
the system more efficiently.
DG
Regulatory authorities must define DSOs as regulators of the distribution market.
Better communication of DSOs with the wholesale market, obtaining information
about the demand curve ant the established agreements.
Furthermore, it is very important to incentivize the firmness of DG to avoid
inefficiencies and possible local blackouts.
Alert State
When the agreements of the national energy market are not compatible with the local
constraints of the distribution network (congestions), the DSOs opens the distribution
market. The distribution market functions in a similar way to the national energy
market. DG and supplier/large customers send their bids and purchases to the DSOs,
who gather the offers and match the energy and the final price of the electricity.
In these situations DSOs, thanks to this system service, provided by regulatory
authorities, can either obtain changes in:
Total product cost
Product cost
TSO services
DSO services
44
The generation schedule of DG or/and
The demand (DSM) through energy suppliers.
Due to this flexibility, DSOs can obtain changes in part of the power flows previously
set in the national energy market, alleviating congestions that would appear on certain
points of the system. All this ensures the security and quality of the supply service.
This market would be regulated by DSOs but it would be ruled by the offer and demand
law.
DSOs need to receive the information from the national energy market, not only of
the demand curve but also of the expected capacity provided by DG. This is vital
for DSOs to analyse and identify possible congestions in the distribution system.
It is necessary to create contracts for these situations when the DG has to change its
production profile. Non-firm access contracts can play an important role in these
situations.
Proper regulatory framework that provides DSOs with system services
(Distribution grid codes and ancillary services) that allow the communication
between DSOs and DG.
Again, the firmness of DG is crucial, because for those cases when more generation
is needed and therefore more DG capacity is required, DSOs must know in which
DG groups they can rely on. For this purpose, it is very interesting to:
Implement services and the technology which allow the DSOs to check in real-
time or close to real-time the availability of the DG connected to the
distribution system.
Incentivize firm DG production contracts so that DSOs can increase their
reliability on DG.
Emergency State
In these cases, and only after all the possibilities of the alert state have been taken into
account, the DSOs have to modify themselves the working conditions of the system.
The actions taken by the DSO could be:
Burden connection or disconnection
DG curtailment or force generation.
The DSOs would be in this cases system actuator since they directly modify the load
and/ or the generation (DG) in order to avoid that a fault spreads to the rest of the
distribution network.
There should be contracts which refund DG producers, the energy that should have
been delivered but actually was not, because of the emergency situation.
DSOs need the proper distribution grid codes to be able to act directly on the final
customers and DG.
45
Additionally, DSOs should implement the required technology to modify the DG
and final customers.
4.1.5 Connection and Access
The access and connection criteria are very important for the planning and operation of
the network. Depending on these criteria, the capacity of the system and its flexibility
will behave differently. Thus, there are different approaches on how to connect the DG
and how the access is provided.
When there is firm connection for DG, it means that all DG applying to be connected
to the distribution network is directly connected connect as long as it fulfil certain
technical requirements. If the connection is non-firm, not all the DG is directly
connected to the grid. Reader must be aware that firmness of connection is a totally
different concept than firmness of the DG.
When there is firm access for DG, it means that all DG already connected to the
network can inject power into it at any time. This is the typical priority access contracts
provided to certain new technologies to incentivize their implementation. Nevertheless,
non-firm access means that despite being connected to the network, the DG can inject
power only when the market and the security of the system allow it.
Combining all these options, there are four different approaches presented in Table 5,
about how to integrate new generation into the system. However, it is not possible an
approach that ensures firm connection and access at the same time.
Access
Firm Non-Firm
Con
nec
tion
Firm X Only operation
approach
Non-firm Fit and forget
approach
Active management
approach
Table 5: connection and access approaches. Source: Own
The three different philosophies or approaches to provide connection and access to the
DG are:
Fit and forget (Passive distribution networks).
This is the current approach and it results in oversized networks. In this approach,
the effect that the connection of certain DG has on the grid is studied only in the
planning step. This approach is only valid for those networks with easily
predictable load, which do not require monitoring tools.
46
Nonetheless, this method is not valid as DER penetration increases because the
network is more dynamic and network load is less predictable. With this approach,
it is needed to reinforce the network to endure higher requirements, resulting in
high expenses for the DNOs. Thus, this approach is not economically efficient for
networks with a minimum integration of DER.
Only operation.
This approach is used currently in those countries with high share of DG. With this
method, in the planning step everything is connected to the grid with no limits. It is
in the operational step when all problems are solved by DNOs. This solution is only
possible on systems with high monitoring levels and multiple system services.
The main drawbacks of this method are:
It limits DG power injections in many hours during the year due to congestions.
It involves high costs for the system, because DG has to be physically
connected to the grid and the system needs to be reinforced to endure the new
conditions.
Intensive work from DSOs, due to continuous congestions and unstable
situations which require the system operator to manipulate the network more
often.
Active management (Active network management).
It is a combination of the two previous perspectives.
First, in the planning step (long-term decisions) DSOs have to decide whether is
convenient to connect more DG or if it is better to reinforce the network using the
power coming from upper voltage levels.
Subsequently and complementing the decisions taken on the planning step, during
the operation (short-term decisions) and thanks to the integration of ICTs
(Information and Communication Technologies), DSOs are able to supervise real-
time or close to real-time monitoring of the system. In this way, DG only injects
power when the market and the constraints of the distribution network allow it.
This approach enables DSOs to:
Optimize future functioning of the distribution system.
Avoid frequent curtailment of DG, making the best of the installed capacity.
Solve operation contingencies in real-time due to a more flexible management
of the distribution system.
Provide ancillary services (similar to those of the TSO on transmission
networks).
47
As a result, DNOs could analyse with more precision if it is convenient to delay the
investment to reinforce the existing assets or to connect more DG.
This is the best approach of all three because it:
Is the most economical and efficient.
Helps to integrate the DER into the system.
Enhances the security of the system.
Evolves towards more active networks management.
Nevertheless, the reader must be aware that this approach demands first an intensive
investment to implement the ICTs into the system. The integration of these ICTs
technologies is one of the main problems that DNOs presently are facing.
Figure 23: DER access and connection approaches. Source: is a representation of this three
approaches and it represents how they relate to each other.
Figure 23: DER access and connection approaches. Source: [7].
a) Connection:
It is the physical connection of the DG to the distribution network. DG highly
influences on voltage variations and congestions in the MV and LV networks. Because
of its influence it is very important that the DG accomplish certain technical criteria
which are essential for the planning and operation of the distribution network.
Technical connection criteria for DG
The technical connection criteria are different in each European country; however, the
essential technical criteria are:
1) The voltage level where DG is connected depends on its installed power. The
higher the installed power of the generator, the higher the voltage level. In Table 6:
48
voltage levels and its typical generation technologies there is a representation of
the typical technologies that are connected in each voltage level.
2) A maximum voltage variation (fixed as a percentage of the voltage level) is
allowed in the connection point of the generation. This is directly related to the
voltage variation control explained in section 4.1.4.
3) Harmonic distortions injected by DG must be reduced as much as possible. This
helps to maintain within certain limits the quality of the product.
4) The power factor must be limited to a certain range (between lagging and the unit).
This helps to maintain within certain limits the quality of the product.
5) The installed power of the DG is limited to a certain percentage of the short-circuit
power of the connection point.
6) Proper protection criteria or coordination of DG electrical protections. The
electrical protections of new DG technologies (such as onshore wind parks, PV, etc.)
actuate when they detect perturbations on the network. When the protections
actuate, DG is disconnected and there is a local drop of voltage that might be
detected by the protections of nearby DG. As a result, close DG also disconnects
resulting into a “domino effect” which can be the origin of emergency situations for
the whole distribution network.
Therefore, the electrical protections of DG cannot actuate when they detect external
contingencies in the network (flickers, voltage drops, asymmetries, etc.). It is
necessary to set up for each type of technology the conditions on which they have
to keep connected to the network despite some type of perturbations occur in the
system.
7) Connection charges. The connection of DG involves expenditures to connect the
generation groups and sometimes the reinforcement of the existing assets.
Depending on the country, these costs are shared differently between DNOs and
producers. Due to the importance of this issue, it is explained into more detail in the
following section.
8) Availability of DG to provide DSOs with metering data. The DG groups must
send to DSOs measures about their working conditions to facilitate the operation of
the distribution network. The importance of this data increases with the voltage
level of the connection point and also for some types of technologies (especially
intermittent RES).
9) To contribute to system’s stability, normally a maximum evacuation capacity is
required. This evacuation capacity is defined as a percentage of the total capacity of
the line or the transformer where the DG in connected.
Typical connection voltage
level
Generation technology
HV (38-150 kV) Large industrial CHP
Large-scale hydro
Offshore and onshore wind parks
49
Large Photovoltaic
MV (10-36 kV) Onshore wind parks
Medium-scale hydro
Small industrial CHP
Tidal wave systems
Solar thermal and geothermal
systems
Large Photovoltaic
LV (< 1 kV) Small individual PV
Small-scale hydro
Micro CHP
Micro wind
Table 6: voltage levels and its typical generation technologies [7].
Besides the technical aspects, the integration of DG within the system requires the
following considerations.
From DNOs’ point of view:
Incentives for DG to connect in areas where it improves the local and the overall
efficiency of the system.
Avoid larger capacity of DG than it is locally needed to supply local demand
connected in the same area, because this can lead to congestions and therefore,
often DG curtailment in alert situations.
From producers’ point of view:
Reduce the lead time and complexity of authorisation procedures and requirements
for the connection of DG to the distribution network.
Common national connection criteria: equal criteria for the whole national territory
and not depending on the region where producers want to locate their generating
group.
Transparency and non-discriminatory criteria for all producers.
Standardised connection criteria: facilitating the connection process.
All this contributes to a clearer regulation that enables producers to be aware of all the
costs of connecting to the distribution network so that they can elaborate more realistic
cost-benefit analysis.
Connection charge
When connecting DG to the distribution network it might be indispensable to reinforce
the existing grid to ensure system’s security. The cost of connecting the DG to the
network is paid by the producer but the possible extra cost of reinforcing the network
can be shared in different ways by producers and DNOs. Depending on how they share
the reinforcing cost, there are three types of connection charges.
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Shallow connection charging:
Producers will cover the cost of the equipment required to connect their generators
to the nearest point of the distribution network.
DNO will satisfy the costs of any reinforcement on the existing network derived
from the connection of the producer.
Advantages:
Those producers using renewable energies can locate their generation groups
where the natural resources can be used in an optimal way. Therefore, the
performance of the RES is the best.
Disadvantages:
This method can result in inefficiencies and higher costs for DNOs.
Too much generation connected at the same point of the distribution system
can increase congestions and therefore, DG curtailment.
Deep connection charging:
All the costs derived from the connection of the generator (physical connection to
the grid and possible reinforcements) are paid by the producer.
DNO does not incur into any expenses.
Advantages:
The producers will connect to the points of the system where it is better for the
overall and local efficiency of the distribution system.
Better utilization of the installed capacity.
Disadvantages:
Due to prohibitively high prices, investments on DG involve more risks
undermining the integration of DG.
Producers who want to use renewable energies may shift to conventional
technologies than can be used at any point (internal combustion energies, gas
turbines, steam turbines, etc.).
Mixed or shallower connection charging:
The connection costs are paid by the producer. Possible reinforcements are shared
by DNO and producers. In cases where several producers connect to the same point,
each of them usually pays the proportional part of the new infrastructure that they
use. In this case it is especially important to establish transparent and non-
discriminatory criteria to calculate the costs and the conditions for the connection.
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Advantages:
It allows producers to locate their generators on those places where resources
are available without incurring in too high expenses.
This type of charging can be used as a mechanism to incentivize firmness of
DG, when shifting from deep to this type of charging mechanism.
There is a trade-off between DG connected wherever it is more efficient (in
case of renewable energies) and where it is better for system’s efficiency and
security.
Disadvantages:
Non clear and transparent regulation can benefit some producers with respect
to others when connecting to the same point.
The reader may have already noticed that some access contracts are
incompatible with some types of connection studies. For instance, in those
countries where “only operation approach” is used, it is senseless to use shallow
connection charging because DNOs would incur in disproportionate expenses.
b) Access:
Refers to the capacity of generators to inject and absorb power over the time. Access criteria are
very important for managing network’s capacity and its flexibility. There are two types of
access contracts for DG: firm DG production and firm/variable access contracts.
Firm/Variable DG network access contract.
DG developers might have the possibility to choose between firm or variable access
contracts. With the variable DG network access contracts producers have the option
of not having firm physical connection to the grid 100% of the time. Variable
access contracts reduce the output of the producer to a predefined limit in
infrequent situation, expected only for few hours a year (when the network is
constrained).
The main advantage of variable access contracts is that it improves the flexibility of
the generation on the distribution networks. This, together with the flexibility of the
demand (demand-side participation) will improve the utilization of the existing
assets.
This type of access contract has to be incentivized in order to compensate such
restriction over the time. Some mechanisms to incentivize non-firm access
contracts:
To use shallow or mix connection charges for firm DG.
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DG developers should be provided with information on expected curtailment
so that they can include it in the risk analysis and economic viability analysis
before they invest.
4.1.6 Information exchange
DNOs have high flexibility in their HV grids (almost comparable that one of
transmission networks) but their MV and LV have poor and deficient flexibility
respectively. Due to the traditional passive approach, DNOs are missing very valuable
information which would improve dramatically the security, the quality and the
efficiency of the service. It is because of this that DNOs should address:
Improving the monitoring level of their MV and LV distribution grids.
Establishing information exchange between DSO and DG.
Establishing information exchange between DSO and TNO.
a) Monitoring level
Increasing the monitoring level and consequently, the flexibility of MV and LV grids is
crucial to evolve towards active system management. In order to enhance this
monitoring level, DSOs have to implement ICTs. However, to integrate the ICTs an
intensive capital is required. This high investment is motivated by the large amount of
electrical substations, components and users comprising these grids.
b) Information Exchange DSOs-DG
Presently, DNOs do not receive any information from the DG. In most of the European
countries DG/RES which are included in the normative concept can inject as much
power as they want and when they want (due to the priority access and other aids such
us feed-in tariffs). This means that the DG included within the normative concept does
not participate in the energy market, so DNOs cannot know how much DG capacity is
being used at any time.
For DNOs to manage better the capacity of their networks, they should be able to:
Receive the expected production schedule and planned maintenances of the DG.
Hence, DSOs will be able to balance the system and avoid other problems such as
congestions, voltage variations, etc.
Assess the availability of every DG group to know the actual DG capacity available
in the system, especially when the demand peaks.
Have access to remote disconnecting of DG when the distribution system is in an
emergency state.
DNOs are a regulated activity, and therefore all this proposals must be provided by
regulatory authorities and subsequently coordinated by the DSOs.
c) Information exchange between DSOs-TSOs.
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The information exchange between DSOs and TSOs can only be achieved by
regulatory rules that set the interface to do so.
DNOs should inform TSO with operational information they need from final
customers connected to the distribution grid.
TSOs should not be able to bypass DSOs. If TSOs need for their operation actions
from DG, the orders should be send trough the DSOs.
Since network activities are regulated, these information exchanges between DNOs and
TSOs can be established only if the regulatory authorities create the proper regulatory
framework.
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4.2 Demand-side Participation (DSP)
4.2.1 Definitions.
The introduction into the distribution network of distributed energetic resources (DERs),
especially the intermittent nature of some renewable energy sources (RES), makes
necessary to improve the flexibility of the system. This flexibility must be achieved on
the generation side (DG) but also on the demand side. Reaching certain level of
generation and load flexibility, will be crucial to offset the intermittency of RES.
On one hand, to increase the demand flexibility is indispensable to make end-users
aware of the real cost of the electricity. End-users thanks to price signals, received
through smart meters, can manage their consumption more actively according to their
preferences. This represents a change of paradigm, shifting from the current “supply
follows demand” paradigm to a higher degree of “load follows supply” paradigm.
On the other hand, DSOs are the ones who have to lead this change of paradigm. DSOs
need to create the proper field where suppliers/ large customers, producers, and other
“product-related services agents” meet. This field should be an open market supervised
by the DSOs but governed by the offer and demand law.
For this purpose, DSOs require more advance tools to manage their grids.
In this context, the concept of DSP within the smart grids framework aims to a more
flexible demand in order to optimize the use of resources and assets at the same time
that integrating the DER.
Since DSP requires actions from end-users and DSOs, the concept of DSP is used as a
concept that embodies two other: Demand-side management and demand response.
Demand-side management (DSM) / Load management
It is the planning and implementation of those actions aiming to influence on the way
that energy is consumed, obtaining desired changes in the demand curve. These actions
oriented to influence the demand are introduced by DSOs.
The desired changes in the demand curve are four:
1. Improve the overall efficiency of the system: all those actions oriented to
diminish the overall consumption or a deceleration of the increasing electric
demand.
2. Shift demand from peaks to valleys: all those methods that enables to transfer
part of the load from peaks to valleys.
3. Fill valleys: mechanisms aiming to fill the valleys with new electric demands such
us: electric vehicle and electric storage.
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4. Reduce demand in critical moments for the system: those techniques that try to
reduce the electric demand when the system is in a critical situation.
Figure 24: Mechanisms of Demand-side Participation [1].
Since the DSOs design the system considering power capacity, the final aim of these
changes in the demand curve is reduce or remove peak load, so that DSOs can postpone
their investments on:
New capacity and
Distribution facilities.
Since DSOs are the ones responsible to introduce these actions, demand-side
management is characterised by a “top-down” approach.
Additionally, DSM affects to DSOs, which is a regulated activity. This means that all
system services included within the context of DSM must be provided by regulatory
authorities and coordinated by the DSOs.
Demand response (DR)
It involves all the changes in end-users’ normal consumption patterns due to variations
on price signals over the time. Subsequently, final customers aware of the real price of
electricity become more active in their electricity consumption usage.
The price signals received by final customers will depend on the network load and the
local conditions of the system. During valley hours without local problems in the
distribution system, the prices will be lower. In contrast, during peak demand hours and/
or local constraints in the network, the prices would be higher.
Since demand response requires that the end-users actually decide to manage their
electricity consumption, it is characterized by a “bottom-up” approach.
On top of that, DR affects to final customers and supplier which are de-regulated
activities. Therefore, the actions included within the context of DR do not require the
creation of new normative.
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As a result of the proper implementation of DSP, some of the possible benefits that each
of the stakeholders of the system will experience are:
Customers: potential lower electricity bills, more market participation and flexible
load contracts.
Suppliers: offer new products and services based on individual consumption
profiles and preferences, better balancing and hedging opportunities.
DSOs: due to DSM tools, DSOs` planning and operation can be improved, delaying
the investment in reinforcements and new capacity at the same time than mitigating
certain grid constraints.
Generator: can optimize investments in peaking generation plants and back-up
capacity.
4.2.2 Demand characteristics
The characteristics of the demand around Europe may differ in many aspects mainly
motivated by the different climatologic conditions and lifestyles in each country.
However, the main variables that determine the demand in any country are:
1) Demand categories: The consumption can be classified into three main groups:
Industry: its profile is more or less constant during the day.
Services: demand higher during the morning.
Residential: demand higher during the evenings.
The importance of each group over the total demand will highly influence the demand
profile. For instance, in the case of Spain these are the profiles of each sector during a
normal working day:
Figure 25: Demand profile of the different groups. [8]
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2) Seasonal behaviour over the year: the energy consumption is higher during winter
and summer and lower during autumn and spring. This is highly related to the
temperature and hours of light.
Figure 26: seasonal behavior of demand. Own based on data from [8].
3) Peak-valleys ratios: the ratio of peak demand over valley demand is very
important for DSOs to determine the required capacity of the system. The higher
this ratio, the less efficient the system because more capacity has to be installed for
only few hour per year. For this reason, DSOs try to reduce this ratio as much as
possible through DSM.
4) Especial events: some important events can influence the demand; for instance:
strikes, sport events, national celebrations, etc. can result in an unusual behaviour of
the demand.
5) Geographic dispersion: the demand has a different distribution and growth than
the generation. The distance between demand and supply is a very important factor.
The more distance between demand and generation, the more power losses and
more problems associated to the transportation and distribution of the electricity.
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Figure 27: Dispersion of the generation and the demand [8].
4.2.3 Lack of demand participation in energy markets: Inelastic demand
When the demand response becomes a reality, all end-users (industrial, services and
residential) will manage their electricity consumption more actively than they presently
do.
Demand response is already a reality for large factories with intensive electricity
consumption (such as steelworks among others). For instance, in some European
countries these energy-intensive factories are incentivized to shift their production to
valley hours (during night), obtaining reduced prices or other benefits as compensation.
Even though demand response already exit for part of the load, demand response must
be extended to the rest of the customers (smaller industrial, commercial and household
consumptions).
However, in many countries household clients have regulated energy tariffs without
variations of price depending on the different hours of the day. Additionally, household
customers have no information about the actual price of electricity and how it
influences on their electricity bill. Because of this, final clients do not find any incentive
to change and manage their electricity usage habits.
Regulated energy tariffs without price signals together with the lack of information of
end-users result in an inelastic demand in the energy market. In other words, the
demand is not sensitive to price variations. No matter how much prices fluctuate in the
energy market, the demand is slightly the same than before the variation of the price.
Inelastic demand is represented in the left part of Figure 28: Inelastic and elastic
behavior of demand.
The main problem of this inelastic demand is that during peak hours, the demand has
neither incentives nor information that motivates them to shift or reduce their
consumption. Therefore, DSOs have to design over-sized distribution networks with
enough capacity for those situations which only represent few hours over the year.
In order to avoid this, DSP aims to introduce an elastic demand with more participation
in the energy markets. This elastic demand would be sensitive to fluctuations in prices,
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reducing its consumption when the price of the electricity increases. This behaviour can
be seen on the right part of Figure 28: Inelastic and elastic behavior of demand.
The integration of the demand into the energy markets require:
Shifting from regulated energy tariffs with static prices to market-reflective
contracts.
End-users to receive price signals.
Figure 28: Inelastic and elastic behavior of demand.
Market reflective tariffs
The electricity bill of any client is made up of two different parts (as represented in
Figure 29: End-users' electricity bill): network access and energy.
Network access: is the charge due to the distribution and transmission services
provided by DSOs and TSOs to the customer connected to the network. This charge
is regulated as an access tariff.
Energy: is the price that customer pays for the product (electricity). This charge
can be regulated or not.
o De-regulated energy price: customers receive direct signal prices from the energy
markets or their energy suppliers.
o Regulated prices: the regulatory authorities regulate the prices of the product. This
contracts present static prices.
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Figure 29: End-users' electricity bill. Source: Own
The integration of the demand into the energy market requires that end-users have either
regulated energy contracts based on price signals or de-regulated contracts.
In Europe, most of European household consumers have regulated energy tariffs.
Therefore, in those countries where static prices exist, regulatory authorities should shift
to market-reflective contracts.
Once those market-reflective contracts are created by regulatory authorities, energy
suppliers can provide them to the end-users, especially to household customers, and
adjust them to their individual needs.
Some of the market-reflective products that regulatory authorities can define are:
Time-of-Use (ToU) contracts: higher “on-peak” prices during daytime hours and
lower “off-peak” prices during night and weekends.
Critical peak pricing: same rate structure as for ToU but with much higher prices
when supply prices are high or system reliability is endangered.
Dynamic (including real-time) pricing: prices vary according to the prices of the
wholesale market.
These contracts and others try to introduce the demand in the wholesale market, at the
same time that helping DSOs to reduce the peak capacity usage and electric
consumption when the stability of the system is in danger.
Very unlikely most of household clients are willing to spend time and effort analysing
the data and trying to optimize their electricity usage based on wholesale markets prices
and the state of the system. For demand response to actually take off is very important
that these products defined in the regulation framework are adjusted to the individual
needs of every costumer. It is because of this that energy suppliers need to manage the
complexity of the products and adapt them to the specific characteristics of each
consumer.
Electricity bill
Network
(service)
Regulated: access tariff
(Adjustment services, by offer & demand)
Energy
(product) De-regulated
( Energy market price signals)
Price signals
Market-reflective contracts
(ToU, CCP, Real-time pricing)
Regulated
Static prices
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Signal prices and information
End-users can manage their consumption only if they are aware of the actual price of
the electricity. For this purpose, DR requires that final customers receive price signals.
The variations of this price signals depend on the prices of the wholesale market and
the stability of the system (local congestion, faults, etc.). In this way, clients can
control their electricity usage based on their preferences and the price signals they
receive.
The technology required to physically send these price signals to final customers is what
is known as ICTs (Information and Communication Technologies). Remarkably
important, within the ICTs, for the integration of demand response are the “smart
meters”.
Complementary to the smart meters, the development of home automation will be
crucial in the future to help final-customers to manage their load effectively.
Smart meters with their functions and home automation will be further analysed in
section 4.2.6.
4.2.4 Planning.
Planning refers to the long-term decisions that the DNOs have to make in order to
provide enough capacity (generation) for the expected future demand (around 15 years
ahead), under secure conditions, considering quality of supply requirements and trying
to minimize the costs. Hence, DNOs invest on those assets and capacity that allow the
supply of the future demand with the minimum cost.
Traditionally, in the planning step the demand has been considered as an external
variable impossible to be modified. Therefore, a conception of “supply follows
demand” paradigm was established. Currently, due to the DSP within the smart grids
framework there is a change of paradigm towards higher degree of “demand follows
supply” paradigm.
Within this new paradigm, demand can offer flexibility and firmness to DSOs, who
considering this demand can determine the necessary capacity of the network. A more
flexible and firm demand and generation (DG) enable DSOs to utilize better the
installed assets and capacity, optimizing and postponing their investments in
distribution facilities and new capacity. At the same time, flexibility and firmness of the
demand represent an essential key for the implementation of intermittent RES.
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In order to obtain such flexibility and firmness from the demand, regulatory authorities
should define distribution grid codes and ancillary services that will result in new
arrangements between DSO and suppliers/large customers.
4.2.5 Operation.
As it was presented in the DG section, the two main operation problems that DSOs face
because of the integration of DG are: congestions and voltage variations. The aim of
this section is to show how DSP can help to solve these two problems.
Congestions
As explained in DG, congestions can occur when the DG force the system beyond its
capacity limits (PG-PL>Pmax) or when there is an excessive demand (PL -PG >Pmax)
leading to outages.
Solution for congestions: State system operation
When describing how to solve the congestion problem from DG point of view, a
distribution market model was defined. This distribution market supervised by the
DSOs, allows them to influence the demand and the generation when the constraints of
the system are surpassed.
In this section, the requirements to introduce the DSP within that market model are
going to be explained.
The functioning of this distribution market would be as follows:
The DSO would receive the demand curve one day in advance from the national
energy market (dairy and intraday markets). Based on the expected demand, DSOs are
able to analyse whether the agreements of the energy market result in local congestion
in some area of the distribution system (the agreements of the national market do not
always match with the local constraints of the network). Therefore, this market referred
to as distribution market, will behave differently depending on the state of the system.
Three different possible states in the system are:
1) Normal State: The demand curve does not violate any constraint of the distribution
system and the system will function smoothly.
2) Alert State: Because of the demand curve agreed in the national energy market,
there can appear local congestions in the distribution system, endangering the
security of part of the system. Generation and demand flexibility are used in these
situations.
3) Emergency State: when the congestions cannot be solved using the flexibility of the
DG and the demand during the alert state or other types of severe faults which
affect an important part of the system occur.
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Normal State
In the normal state, the distribution network runs smoothly. The DSOs act as operators,
supervising the security and quality of the supply service. This task is performed by
monitoring in real-time the conditions of the distribution network.
When the system is in normal state, the distribution market is not operating. The
distribution markets manage system service to help DSOs to coordinate and control the
balance between generation and demand, ensuring the quality of the service and using
the system more efficiently.
DSP
Contracts incentivizing the firmness of demand (end-users stop consuming in
certain moment obtaining benefits in their electricity bill), could be an important
element to avoid inefficiencies and possible local constraints.
Better communication of DSOs with the wholesale market, obtaining information
about the demand curve ant the established agreements.
Alert State
When the agreements of the national energy market are not compatible with the local
constraints of the distribution network (congestions), the DSOs opens the distribution
market. The distribution market functions in a similar way to the national energy market
or wholesale market. DG and supplier/large customers send their bids and purchases to
the DSOs, who gather the offers and match the energy and the final price of the
electricity.
In these situations, DSOs use the system services to communicate with large customers/
energy suppliers. Thanks to these services, provided by regulatory authorities, DSOs
can either obtain changes in:
The generation schedule of DG or/and
The demand (DSM) through energy suppliers.
These changes allow DSOs to obtain changes in part of the power flows previously set
in the national energy market, alleviating congestions that would appear on certain
points of the system. All this ensures the security and quality of the supply service.
This market would be regulated by DSOs but it would be ruled by the offer and
demand law. The DSOs would be market facilitators but not actuators.
DSP
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Regulatory authorities should define market-reflective contracts that allow more
flexible demand. A more flexible demand resulting from flexible contracts, will
allow the demand to participate in the distribution market.
Proper regulatory framework that provides DSOs with system services (ancillary
services and grid codes defining the criteria on which the ancillary services are
based) that allow the communication between DSOs and large customers/ suppliers.
DSOs must create tools that allow them to simulate their distribution networks,
improving the detection of possible congestions in the system.
It is crucial to implement ICTs (especially smart meters) because:
o They provide price signals and other information that makes aware the
consumer about higher prices (motivated by the alert state).
o They provide useful information for DSOs about the state of the demand. This
helps DSOs to supervise in real-time whether there is any influence on the
demand or not when a congestion problem is being managed.
Emergency State
In these cases, and only after all the possibilities of the alert state have been taken into
account, the DSOs have to modify themselves the working conditions of the system.
The actions taken by the DSO could be:
Burden connection or disconnection
Force generation from DG or curtailment.
The DSOs would be in this cases system actuator since they directly modify the load
and/or the generation (DG) in order to avoid that a fault spreads to the rest of the
distribution network.
DSP
For the DSOs to be able to modify directly the demand, distribution grid codes
need to be defined by regulatory authorities. In this way, DSOs can use the grid
codes to take the actions required to keep the security and quality of the service.
Grid codes usage should be limited to specific situations and only after flexibility of
demand has been totally used.
Additionally, DSOs should implement the required technology to modify the
demand.
4.2.6 Technology and information exchange
In the future smart grids, the development of technology is necessary in order to:
Increase the visibility of the DG, demand and the distribution network.
Introduce the DR into the wholesale market.
Facilitate the communication and integration of all agents involved in the system.
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For this reason, it is necessary to provide DSOs with proper tools. At the same time,
ICTs-based technologies are essential to facilitate the communications between agents.
a) Technology and tools for DSOs.
DSOs require new tools to meet their tasks (security, reliability and quality of service)
at the same that integrating DER. These tools will improve their planning and
operability capability, allowing them to use more efficiently the existing capacity and
distribution facilities. These tools are:
Forecasting tools: new and more accurate forecasting tools together with the
flexibility and firmness of the demand will improve the efficiency of the existing
and future distribution assets. These tools are a complementary to the study tools.
Monitoring tools: any problem that cannot be detected cannot be solved. DSOs
need to improve the monitoring and supervision of their networks, DG and demand
to improve the security and efficiency of the system.
Actuation tools: once there are proper monitoring tools, the next step is to
enhance the actuation tools. DSOs must improve their system operability to be able
to modify themselves the demand or generation profiles and schedules. These
actuation tools must be complemented with ancillary services and distribution
grid codes, properly defined by regulatory authorities.
Study tools: The planning and operation of distribution networks need that DSOs
create and set up simulation and study tools. These tools allow DSOs to analyse
their networks’ behaviour in different scenarios before they actually occur.
For instance, these tools can play a crucial role for the DSOs when locating possible
local congestions in their distribution network.
Data management tools: in the future smart grids, in order to integrate all the
agents of the system using ICTs-based technologies, enormous volumes of
information need to be managed. This requires complex and robust information
infrastructure and tools to manage that information.
b) ICTs-based technology.
The ICT-based technology such as SCADA (Supervisory Control and Data
Acquisition), DMS and automated devices with self-healing capabilities are essential for
keeping the stability of this complex system. However, from a DSP point of view, the
most important aspect of the ICTs is the Advance Metering Infrastructures (AMI).
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AMI are systems whose function is not only metering as current electrical meters but
also gathering and analysing the information about the use that end-users make of the
electricity.
From the DR point of view, the most important component within the AMI is the “smart
meter”.
Smart Meter
Smart meters are the communication link between end-users and the distribution
network. Smart meters allow final customers to receive price signal and other important
information.
From the DR point of view, the smart meters are the gateway to receive price signals
and other information, increasing their awareness of end-users and allowing their
participation in the energy market.
From the DSM point of view, the smart meters are the technological solution for DSOs
to coordinate the system services defined by regulators.
Smart meters will manage constant bidirectional flows of information. This information
can be classified in three different categories:
Technical data: information required by DSOs about final customers’
consumption to operate and plan the distribution network and supervise that the
power quality thresholds are not exceeded.
For final customer, it is very important to ensure secure information exchange so
that unauthorised parties cannot maliciously modify their energy supply.
DSOs have to create secure communication channels and control of their
distribution networks to achieve their responsibilities.
Some examples of this data could be:
Remote connection/disconnection of supply.
Remote management of alarms and events from meters
Remote metering
Remote adaptation to topology changes on the network.
Quality of supply data.
Static data: all that information required for administrative purposes. This data is
the same than current electrical meters. For instance:
Registration of new smart meters.
Control of demanded active power (limiter).
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Commercial or product data: it is the data related to available products and other
information that allow end-users to select the offer that best suits them.
In order to create innovative offers, suppliers must analyse their customers’
electricity usage. For this reason, energy suppliers must have timely access to their
consumers’ consumption data.
This data can be:
Remote setting of selected tariff: those parameters related to the contract
agreed between supplier and end-consumer.
Remote metering.
Fraud detection.
Information for end-users about their consumption patterns.
Energy box, automated houses and smart appliances
When describing the concept of demand response, it was mentioned that final
costumers will modify their consumption based on price signals and their preferences.
The response of the final customer can be:
Manual: customers see the prices in the displays of their smart meters and they
decide how to manage their consumption.
Automated: the consumption patterns of final customers are automatically managed
by a complementary technology.
The components necessary for a proper automated demand response are three: the
energy box, automated houses and smart appliances.
The energy box is an electronic device which manages the household consumption
based on:
price signals received from the smart meter
and the setting established by final customers about their comfort and electricity
usage preferences.
Additionally, the integration of automated houses together with smart appliances are
facilitators. Automated houses will consider the local condition of the house and thanks
to the smart appliances, they will be able to optimize the use of electricity (choose the
option which consumes the least maintaining the comfort conditions of the house).
Of course, these two elements are not obligatory and as facilitator, the will be purchased
by those clients who are willing to pay for such investment with the idea of recovering
the investment along the time for the saved electricity.
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5. The new role of the DSO and regulatory framework
recommendations. 5.1 Planning.
The integration of DERs, in certain conditions, can help DSOs to improve the utilization
of the already existing capacity and electrical facilities. Therefore, DERs must be
properly integrated in the distribution system to improve the overall efficiency of the
system avoiding oversized systems.
At the same time, DSOs must accomplish their tasks, especially ensuring the quality,
security and reliability of the supply service. Thereby, the proper integration of the
DERs into the system is essential to improve the overall efficiency of the system while
maintaining the quality, security and reliability of the service.
For DSOs to take into account the capacity of DERs in the planning step, DERs must
provide firm capacity so that DSOs actually can use that capacity when the security of
the system may be jeopardised. To integrate DERs into the planning step, the most
important aspect is to encourage the firmness of these DERs.
In this dissertation, DG and DSP are the only two DER considered, but many of the
ideas that are presented in this chapter can be applied for the future integration of
decentralise storage and electric vehicle.
5.1.1 Firmness of DG.
Firmness of DG means that, the capacity of the DG connected to the distribution
network must be available to support the DSOs in the operation of the system when it is
needed (when load peaks and security of the system is endangered).
Within the technologies deployed in DG, two groups can be distinguished:
dispatchable and non-dispatchable technologies.
Dispatchable technologies (Internal combustion engines, combined cycles, nuclear
plants, Biomass, etc.) are technologies that can produce electricity at any time they are
required, as long as they have the fuel they need.
Conversely, non-dispatchable technologies (wind power, solar PV, solar thermal, etc.)
are technologies that depend on primary sources that cannot be controlled.
Firmness of DG in strongly related to the technology. Conventional technologies can
start producing electricity when they are activated, but non-dispatchable technologies
can only produce when the atmospheric conditions are adequate.
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Thereby, from the firmness point of view it might seem better to install conventional
technologies based on fossil fuels. However, it is important to diversify the mix of DG.
This is because one of the objectives of DG is to use renewable energies to reduce the
external dependence at the same time than reducing the environmental impact.
For this reason, it is important to install conventional generation that provide firmness
to DSOs but also renewable energies.
The most feasible solution to reduce the intermittency of DG RES is to incorporate
decentralise storage. In this way, the electricity produced in those moments when it is
not required, can be storage and then injected into the network in other moments when
the system demands more capacity but the non-dispatchable technologies are not
working because the wind is not blowing, the sun is not shining, etc.
Presently, the technologies deployed in the electrical storage are very expensive and in
most cases, it is cheaper to invest in the network rather than investing in these
technologies. Hence, technological investigation and development of these technologies
is crucial for the proper integration of intermittent technologies.
To incentivize the connection of firm DG, regulatory authorities should establish:
Shallower charge instead of deep charge to those technologies which are able to
provide firm capacity service.
A framework on which DSOs provide to DG developers with clear information
about when firm capacity services are to be required by DSOs.
Create the market platform (referred to as “firm DG capacity market”) where
DSOs and DG can meet to manage the capacity.
5.1.2 Firmness of Demand
Firmness of Demand is to reduce/stop consuming when the DSOs require it to alleviate
the constraints of the system in a certain area. Therefore, firmness of demand helps in
postponing investments in extra capacity that may be used only few hours in the year.
In order to incentivize firmness of demand, regulatory authorities must create a market
platform where DSOs can meet with energy supplier/ large customers, offering them
incentives to reduce the demand during certain hours of the year. This platform is called
“firm demand capacity market”.
The combination of the firm DG/ demand capacity markets provides the DSOs with an
important tool for the Demand-side management, the “Firm capacity management”.
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5.1.3 Firm capacity management: Firmness markets for DG and Demand.
The market for firmness of DG and Demand must be two different markets, but in any
case they should be co-ordinated by the DSOs.
DSOs should use the option which is cheaper (firmness of DG or/and demand) for each
situation in a certain area.
The reader must be aware that the active participation of the demand (elastic demand) in
the electrical markets will diminish peaks and alleviate certain constraints in some
areas. Nonetheless, not in all the areas of the system, the constraints will disappear.
Therefore, the firm capacity management through these two markets will remain as a
useful tool for the planning of distribution networks.
5.1.3.1 Functioning of firm DG capacity markets.
To understand the functioning of this market and the objective, Figure 30 represents in
the right side, the monotonous curve the demand in a year for the transformer presented
in the left part of Figure 30.
Figure 30: Possible distribution network topology and the monotonous demand curve for the
transformer during a year.
In the monotonous curve of Figure 30, there are a number of hours on which the
capacity of the demand surpasses transformer’s capacity. In this situation the DSO
could either reinforce the network by installing second transformer (option which takes
between 3-4 years at least) or use the DG connected to that area to cover the exceeding
capacity. The aim of these markets is that the DSO can use the firmness of the DG
connected to that point to provide the extra capacity required.
First, DSOs create the monotonous curve of the expected demand for a certain year.
Based on the expected demand and the capacity of their network for that year, they can
detect the areas and number of hours when this extra capacity will be required.
Secondly, this extra capacity is offered to the DG connected to that area, so that the
DSO can obtain that extra capacity from them. The best mechanism to offer this firm
capacity is creating a market of firm DG capacity.
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Therefore, regulatory authorities must create a market with the following characteristics:
One year in advance the DSO, responsible for the area with a transformer that will be
overloaded during certain hours a year, opens a market where they offer that firm
capacity to the DG connected to that area for a number of hours. In a similar way as in
the intra-day markets, DG producers will send their bids about their firm capacity to the
DSO for a number of hours (based on DSOs predictions) in the year, as depicted in
Figure 31:
Figure 31: Bids of firm capacity of DG producers connected to a certain area.
The DSO gathers all the offers and orders them according to the price. Those with the
lowest price and providing the firm capacity required are the ones which will provide
the firm capacity service to the DSO. In this way, the DSO avoids investing in new
assets, because the DG offers the extra capacity required.
In the real-time operation, when the DSOs decide to use this service, DSOs have to pay
to DG for this service at the marginal price established in these markets (OPEX).
National Regulatory Authorities must allow this communication between DSOs
(regulated activity) and DG (de-regulated activity).
If is happens that DG is not available when it is supposed to be providing firm capacity,
then it would be penalized.
There can be cases when the DG connected to an area come to an agreement and
establish a collusion of their bids. However, if the bids offered by DG are too high,
DSOs would rather reinforce the network (CAPEX) instead of using these services
(OPEX). As a consequence, the DG would lose the potential benefit that they could
obtain from participating in this market.
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5.1.3.2 Firm Demand capacity markets.
This market can be considered as part of Active Demand-Side Management, since it is a
tool for DSOs to remove peak load and defer the installation of new capacity and
distribution facilities.
Firmness markets for demand will be used when:
There is not enough DG to provide the extra capacity required in an area.
There is no DG connected in that area so local constraints can be only alleviated
by reducing the demand’s capacity.
Procuring this service is cheaper than procuring firmness of DG in that area.
Figure 32: Possible network topology of a certain area with few DG and its monotonous demand
curve.
To understand the functioning of this market and the objective, ¡Error! No se
encuentra el origen de la referencia. represents in the right side, the monotonous
curve the demand in a year for the transformer presented in the left part of ¡Error! No
se encuentra el origen de la referencia..
In the monotonous curve of ¡Error! No se encuentra el origen de la referencia., there
is a number of hours on which the capacity of the demand surpasses transformer’s
capacity. In this situation the DSO could either reinforce the network by installing
second transformer (option which takes between 3-4 years) or try to reduce the peak
incentivizing the demand to do so.
First, the DSOs create the monotonous curve of the expected demand for a certain year.
Based on the expected demand and the capacity of their network for that year, they can
detect the areas and the number hours when the system will be locally overloaded.
Secondly, the DSOs will organize a market on which the energy suppliers with their
aggregate demand in a certain area and large customers voluntarily participate.
The energy suppliers/ large customers would send their bids of how much capacity they
can reduce a number of hours during the year and the price the offer because of
reducing that capacity.
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The DSO of that area, as operator of this market, would gather the offers and order them
according to the price. When the DSO covers the required capacity, the marginal price
is established. This process is represented in Figure 33.
Figure 33: Functioning of the firm capacity of demand market.
In the real-time operation, when the DSOs decide to use this service in an area, they will
pay to energy suppliers/ large customers for the provided service at the marginal price
established in the market of that local area (OPEX).
Energy suppliers will be penalized if they do not reduce the agreed capacity in the hours
when the DSOs ask for it. Therefore, the energy supplier participating in these markets
will use different incentivizes to reduce their aggregate load in those hours. The
mechanisms that each energy supplier creates to obtain this reduction will depend on
their business model and it is not an issue of the NRA.
The firm capacity management markets will be used by the DSOs until the point
where investing in new reinforcements (CAPEX) and procuring firm capacity from
DG/Demand (OPEX) in an area breaks even in the long-term time scale. For the case
presented in Figure 30 and ¡Error! No se encuentra el origen de la referencia., this
situation would be when installing a second transformer and all complementary
reinforcements (CAPEX) is as expensive as purchasing firm capacity from DG/Demand
(OPEX). When both options are the same cost, DSOs will invest in the reinforcement
(CAPEX).
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Regulatory recommendations for allowing firm capacity management markets.
Create the two types of markets according to the description above detailed.
Allow the information exchange between DSOs (regulated activity) and DG,
Energy suppliers/ large customers (de-regulated activity).
5.2 Connection and Access
5.2.1 Connection and access requirement for DSO
As DG increases its penetration into distribution networks, DSOs need to shift
from the traditional passive approach to a more Active Management Approach.
In Table 7, the different approaches are presented.
Access
Firm Non-Firm
Con
nec
tion
Firm X Only operation
approach
Non-firm Fit and forget approach Active management
approach
Table 7: Connection and access approaches. Source: own.
Passive approach results in inefficient and oversized distribution networks if there is an
important share of DG. This is because the network is reinforced for the worst operation
conditions (excessive investments in CAPEX).
At the same time, Only Operation approach results as well in oversized systems (many
DG groups connected to the grid) and many instability situations that require continuous
intervention of DSOs (excessive investments in OPEX).
The active management approach is the best philosophy because both, planning and
operation are considered as complementary. During the planning step, DSOs consider
how the connection of new DG will affect the system. Complementarily, during the
operation thanks to real-time information exchange and the system services, DSOs
improve the flexibility and efficiency of the system (trade-off between CAPEX and
OPEX).
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5.2.1.1 Connection based on Active management approach.
When DG developers propose DSOs to connect in a certain area, the DSO offers
different points where the DG can connect to the network.
Previously, before deciding whether to allow the connection or not and where, DSOs
must perform a long-term analysis. During the planning step, DSOs must consider
whether the connection of new DG capacity will provide better quality, security and
reliability of supply service for the local distribution network and the system.
Only when quality, security and reliability are ensured, DSOs will offer DG developers
the different connection points and the costs of each option.
5.2.1.2 Network access based on Active Management Approach.
The access of DG to the grid is closely related to the operation of the network. Within
the active management approach, DSOs should incentivize the shift from firm network
access contracts to non-firm access contracts.
Non-firm access contracts
Objective of these contracts
Chase the global efficiency of the system considering the economic interests of DG
and DSOs.
How do they work:
This contract establish a number of hours in a year, when DSOs can reduce/ stop
DG’s feed-in due to congestions in the area where that DG is connected. These
infrequent situations are expected only for few hours per year.
How DSOs establish the times and duration of the curtailment:
DSOs require tools for monitoring, simulation and forecasting of the networks.
DSOs using these tools and based on the expected demand and the characteristics
of the network can determine the number of hours on which the DG in a certain
point may be required to reduce/stop injecting power into the network.
The number of hours of possible curtailment must be communicated by the DSO to
the DG developer. In this way, DG developers can include these curtailments in
their risk and economic viability of the business
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How do DSOs use this contracts:
When the DSOs face local congestions, they will curtail the DG which accepted
this contract. When the DSOs make use of this service, they have to pay for it
(OPEX). These contracts are essential for the system service “Security congestion
management” in the alert state.
DSOs must determine when it is more cost-effective to invest in procuring this
service (OPEX) than investing in new reinforcements (CAPEX) in an area of the
network in a long-term scale (planning). There is no one-size-fits-all solution, due
to the variety of topologies and characteristics of the distribution networks.
For this analysis, DSOs need to improve their tools for monitoring, simulation
and forecasting of their networks (especially in MV and LV networks).
Furthermore, DSOs need the proper technology to remotely curtail/disconnect
from the SCADA system the DG.
Criteria used to curtail DG:
In the operation time-scale, there can be situations when there are several DG
groups connected to the same point with these variable access network contracts.
For this situations NRA must define the criteria to curtail the minimum number on
producer at the minimum cost.
Therefore, National Regulatory Authorities should define the following criteria:
If DSO considers that reducing the feed-in of all DG groups is enough to solve the
constraint:
1) All DG groups should reduce their output to a defined level. (always taking
into account the security factors of the DG groups, such us technical minimum)
If it is not enough to reduce the feed-in of all of them, some DG has to stop
injecting power. For this situation:
2) The criterion will be based on the system services provided by each DG group
(different technologies offer different system services). The preference of the
system services will depend on the characteristics of the local area (topology,
DSOs active elements, etc.). DSOs must decide what DG provides more
security to the system.
3) Finally, in similar conditions, DSOs must disconnect those DG groups with
higher costs.
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The basic idea of these criteria is to ensure security first and then the economic
aspect.
How to incentivize these contracts:
DSOs should offer shallower connection charges to DG developers.
Bad planning of the DSOs-
This type of contract establishes a limited number of hours in which the DSO can
curtail DG with variable access network contract.
The main problem that DSO has to face is that because of a bad planning,
congestions occur more than expected. This motivates that before finishing the year,
the DSO has already depleted those hours.
DSOs have to keep the security of the system under any circumstances and if they
make a bad planning, they would incur in higher expenses to solve the problems
through other ways.
For this reason, NRA must incentivize DSOs the investment of better tools for
monitoring, forecasting and simulation of their networks.
Regulatory recommendations for the establishment of non-firm access contracts
access contracts.
Regulatory authorities must define variable access network contracts that can be
offered from DSOs (regulated activity) to DG (de-regulated activity).
NRAs have to define how to regulate the OPEX and the CAPEX.
Incentive DSOs to invest in new tools (monitoring, forecasting and simulation) for
a better operation.
5.2.2 Connection and access requirements for DG and Demand
5.2.2.1 Connection requirements from DG’s point of view.
When DG developers request connection to the distribution network, there several
aspects that must be well defined and clearly specified by regulatory authorities:
Technical connection criteria
First of all, clear technical connection criteria. When analysing the technical
connection criteria in section 4.1.5, some the most important were described. However,
DSOs depending on the characteristic of their network must establish those which
improve the planning and operation of the system.
Within these criteria, the most important is the protection criteria for new technologies
(especially renewable energies and cogeneration). Presently, new generation
technologies are disconnected when their electrical protections detect disturbances on
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the network. However, generators should keep connected to provide stability to the
system when there are faults in the distribution system. Therefore, DG must keep
connected to the network even though disturbances appear in it.
Each generation technology has different characteristics and not all of them can tolerate
the same disturbances. To adapt the protection criteria of each technology, regulatory
authorities should use international standards such as UNE and IEC.
Connection charges
Secondly, it is important to define what type of connection charges is used.
In the case of deep connection charge, DSOs must provide a cost study of the different
options for the connection of each DG and possible reinforcements.
In case of using shallower connection charge, the cost of the connection and the
annually payment (cost of network use) must be presented clearly to DG developer.
This annual payment must be socialized between all DG connected to the same point.
Shallower connection charges are recommended for DSOs to incentivize DG to accept
variable access contracts, to provide system services and firm DG.
Additional requirements
DG developers must implement ICT technologies to provide DSOs with necessary
information such as:
State of the DG (DSO can check in real-time if a specific DG group is available)
Maintenance and outages periods.
Production schedule and actual dispatching.
Additionally, these ITCs will allow DSOs from their SCADA system to curtail DG in
secure conditions when the system is in an emergency state or when DG are curtailed
due to variable access contracts.
The cost of implementing the necessary ITCs should be shared between the DG
producers and the DSOs, since both of them will use this technology.
Moreover, when DG connects to the distribution network it must be equipped with the
necessary technology to provide at least mandatory system services (DSO voltage
control, anti-islanding operation and islanding operation) and some others (that DG
developer may want to provide using the system services market.
General recommendations
On top of that, NRA should:
Reduce the lead time and complexity of authorisation procedures and
requirements for the connection of DG to the distribution network.
Transparency and non-discriminatory criteria for all producers.
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Standardised connection criteria for the national territory: equal criteria for the
whole national territory and not depending on the region where producers want to
connect.
5.2.2.2 Connection requirements from demand response’s point of view.
For the integration of the demand response, the most important element is the smart
meter. Regulatory authorities should:
Make mandatory the installation of smart meters for new customers.
Develop plans to gradually integrate the smart meters for those customers who are
already connected.
The smart meters will allow consumers to receive information about prices contracts,
etc. Meanwhile, for DSOs they will provide the information about their consumption
habits and other data required for the correct planning and operation of the network.
Smart meters will manage constant bidirectional flows of information. This information
can be classified in three different categories:
Technical data: information required by DSOs about final customers’
consumption to operate and plan the distribution network and supervise that the
power quality thresholds are not exceeded.
For final customer, it is very important to ensure secure information exchange so
that unauthorised parties cannot maliciously modify their energy supply.
DSOs have to create secure communication channels and control of their
distribution networks to achieve their responsibilities.
Some examples of this data could be:
Remote connection/disconnection of supply.
Remote management of alarms and events from meters
Remote metering
Remote adaptation to topology changes on the network.
Quality of supply data.
Static data: all that information required for administrative purposes. This data is
the same than current electrical meters. For instance:
Registration of new smart meters.
Control of demanded active power (limiter).
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Commercial or product data: it is the data related to available products and other
information that allow end-users to select the offer that best suits them.
This data can be:
Remote setting of selected tariff: those parameters related to the contract
agreed between supplier and end-consumer.
Remote metering.
Fraud detection.
Information about end-users’ consumption patterns.
For DSOs, smart meters constitute a very important component in the monitoring of
load. At the same time, they will allow a more active participation of final customer
obtaining potential benefits derived from the contracts agreed with their energy
suppliers. Therefore, the investment required to implement the smart meter should be
shared between the DSOs and final customers.
5.2.2.3 Access requirements from DG’s point of view.
In this aspect, DG developers must receive clear information about the variable access
contracts.
Non-firm access contracts
DG developers must be provided with the following information:
The number of hours that their DG may be curtailed/ stopped during each year.
Incentives received because of accepting these contracts. Since these contracts provide
non-firm access to DG, regulatory authorities should allow DSOs the possibility to offer
shallower connection charges to those DG developers who accept these contracts.
All this information is required by DG developers to develop a realistic risk and
economic viability analysis prior to invest in the project. If the results are positive, the
DG developer will accept non-firm access contracts.
5.3 Operation
5.3.1 System state model and system services as tools for the DSO.
System state model
For the operation of the system, regulatory authorities should create a model on which
the operation of the system depends on its state. For this purpose, regulation should
define the following three states:
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1) Normal State: the constraints in any part of the system are not violated and the
balance between generation and demand is even.
There are bidirectional flows of information between all the agents involve in the
system. Therefore, the distribution system is functioning smoothly and it does not
require either actions from DSOs nor use of system services.
2) Alert State: the demand curve agreed in the national wholesale markets, can
originate local congestions and voltage variations in the distribution system
endangering the security of part of the system.
In this state, DSOs use flexible service-based markets where system services
provided by DERs (DG, Demand, decentralised storage and electric vehicle) can be
purchased by the DSOs to solve the operation problems.
3) Emergency State: the system will be in this state when:
The congestions and voltage variations that cannot be solved through market tools.
Severe faults.
Restoration of outages.
For these situations, the DSOs will either use other system services (mandatory system
services with/ without compensation) or remote control the generation and demand
connected to their distribution network.
These situations are expected to happen very seldom, but due to their threat for the
system’s security DSOs have to be able to rapidly intervene in the system.
REGULATORY RECOMMENDATIONS
Regulatory authorities should define different states for the system following the
description above explained.
NRA should create the system services that can be managed for each of the states.
These System Services are specified in section 5.3.2.
NRA should create a market for the alert state, where DSOs can purchase system
services from the DERs to solve operational problems.
NRA should define DSOs as co-ordinator of the market for system services during
the alert state.
NRA should define the Distribution Grid Codes that define each of the ancillary
services. NRA can optionally assign this task to DSOs.
5.3.2 Concept of system services and system services required for each state of
the system.
5.3.2.1 System services definition.
System service is a concept made up of two other concepts:
Ancillary Service
Distribution Grid Codes
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Figure 34: Concept of System Service.
The Ancillary services are commercial services procured by system operators (TSOs
and DSOs) from network users (DERs). These services are necessary for ensuring the
supply of electricity in the required security, quality and reliability conditions.
The Grid Codes define the specific characteristics of each ancillary service and how it
works. The grid codes determine:
Purpose of the ancillary service
Form of delivery: mandatory with/without compensation or voluntary through
system services markets.
Who provides the ancillary service.
Required information flows.
Criteria and procedures for the application of the ancillary service.
Other specifications required for the good functioning of the ancillary service
(how to monitor, calculate and audit it).
These services allow DSOs to postpone the investments to reinforce the distribution
network. Therefore, system services play an essential role from a Demand-Side
Management point of view. As a consequence of these system services, there will be
new agreements between DSOs and DER/large customers/energy suppliers trying to
maximize their benefits at the same time that improving the quality, security and
reliability of the service.
5.3.2.2 System services required for each state.
In Table 8, the system services which are considered essential are represented, but
depending on the characteristics of each network NRA may have to define other system
services for the DSOs.
A) Normal State
System Services
Ancillary Services
Grid Codes
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During the normal operation state, the only system service required is information
exchange between all the agents of the system.
B) Alert state.
For the alert state, regulatory authorities should create the following system services:
Firm capacity management.
DSO voltage control.
Losses compensation
Security congestion management (using non-firm access contracts).
Islanding Operation.
All these system services are used by the DSOs to come back to the normal operation
state. These services can be either commercial or mandatory, but in any case DSOs pays
for the use of these system services (OPEX).
DSO voltage control
Presently, the main problem that leads the distribution networks to the alert state is that
DG connected to the distribution network does not support DSO in the tasks of
controlling voltage variation and reactive power transportation.
Controlling voltage variations and power flows is becoming a complex task for DSOs
due to the lack of support of DG. Since reactive power cannot be transported over
long distances, in areas where there is a high share of DG but not conventional sources
of reactive power, the support of DG is crucial.
For this reason, NRA should define DSO voltage control as mandatory for DG.
However, in the case of being in the alert state it will be mandatory with compensation.
In contrast, in the emergency state this system service will be mandatory without
compensation.
Additionally, in those areas where DG’s reactive capacity is not enough to offset the
effect of their active power injection, DSOs should reinforce the network installing
conventional equipment (CAPEX): transformers, capacitor banks, etc.
The DSOs will delay the investment in the network until the point when incursions in
the alert state become too often. When these incursions are too often, for DSOs it is
more expensive to procure this service (OPEX use this service many times in the year)
than investing in reinforcement of the network (CAPEX tap-load transformers,
capacitor, reactance, etc.).
C) Emergency state.
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The system services used in the emergency state are:
Anti-islanding operation.
DSO Voltage variation (emergency state).
Security congestion management (emergency state).
Black start.
In this case, DSO will not pay for the use these system services. Due to the urgency, the
DSOs will directly modify the demand or/ and the generation they consider that will
solve the problem. Hence, for this state it is necessary to establish the criteria for
curtailment and the compensations due to such modifications.
Curtailment of DG/ Demand in emergency state.
When the system is in an emergency state and the use of the system services from the
alert state did not solve the local/ general problem in the system, DSOs must disconnect
generation and/or burden to solve the problem.
Regulatory authorities must:
Define Grid Codes to establish how the curtailment should be performed affecting
the minimum number of users and resulting in the minimum cost for DSOs.
Define criteria to compensate DG and demand for the restrictions on their
electricity usage. As a reference:
For DG, these criteria should be based on the energy that a curtailed DG group
had dispatched if it would not have been curtailed.
For demand, the criteria should be based on: contracted power (not the same
industrial client than household), hour of the day and contract of the client and
consumption habits during curtailment hours.
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System
Service Objective Provided by Information Exchange Form of delivery
Information
Exchange
Optimize DSOs and TSOs
control, supervision and
scheduling
DSOs↔DG
Production schedule, real-time generation output,
maintenance periods, outages, real-time availability of DG.
(DG DSO).
For DG RES weather forecast (DGDSO).
Number of hours of curtailment due to variable access
contracts (DSODG).
Mandatory with
compensation
DSOs↔Energy
suppliers/large customers
Technical, static and commercial information from the
demand (Energy suppliers/ large customers Smart
metersData hubsDSOs).
Commercial information from final customers (Smart
metersData hubsDSOenergy suppliers).
SO↔DSOs↔TSOs
DG production schedule (DSOTSO).
TSO Real-time and off-line measurements and topology
information (TSODSO).
TSO outage programs and availabilities information
(TSODSO).
Visualization of the demand curve of the wholesale market
(SODSO).
Firm capacity
management
(long-term)
DSO planning purpose;
optimize the network
capacity’s utilization
through flexible capacity of
DG and Demand
DG CHP, small
hydro, RES with
integrated storage.
DG outage programs and availabilities information
(DGDSO)
Real-time generation output (DGDSO).
Real time demand flexibility information (DERDSO)
Firmness periods (DSODER). Commercial
Demand Energy
suppliers/ large
customers
Real-time demand (Smart meterdata hubsDSO).
Real time demand flexibility information (DERDSO)
Firmness period (DSOEnergy suppliers/large customers)
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DSO voltage
control
Local supply quality
security and increasing
amount of DG power that
could be injected in the grid.
Photovoltaic, Wind
Power, CHP,
Decentralized Storage,
Demand-side
Management.
Reactive requirement (amount and electrical or geographical
delivery location) (TSODSO).
Real-time load and network voltage or fault conditions
(DSODSO).
Real-time generation output (DG DSO).
V, Q, pf setpoints (DSODG).
Commercial for purposes
beyond maintenance of
network stability or
outside the scope of the
customer’s own
connection.
Mandatory without
compensation to maintain
defined limits for
distribution
System stability.
Losses
compensation
Improve the efficiency of
the system
DSO, DG, Demand
Response
Real-time load and network voltage or fault conditions
(DSODSO).
Real-time generation output (DGDSO).
V, Q, pf setpoints (DSODG).
Demand reduction signals (DSOAggregators).
Commercial
Security
congestion
management
(short-term)
Operate the grid within the
security standards
RES, CHP, Decentralized
Storage, Demand-side
Management.
Real-time load and network voltage or fault conditions
(DSODSO)
Real-time generation output & load flexibility (DGDSO)
Reduced setpoint/ reduction signal (DSODG)
DG outage programs and availabilities information
(DGDSO)
Mandatory with
compensation
or by commercial
arrangement (non-firm
access contracts)
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Islanding
operation
Improve continuity of
supply when higher voltage
source is unavailable
DG, storage, DSO (local
network controls), DSM
Real-time active and reactive power flows information
exchange (DERDSO)
V, P, Q setpoints (DSODER).
Mandatory with
compensation
Anti-islanding
operation
Avoid unsafe, unbalanced
and
poor quality distribution
electric islands
DG, Decentralized
storage, DSO (local
network controls)
Local automatic signal generated in case of fault or triggering
conditions all local DG, storage, network control points
Local signal generator DSO SCADA or central control
(and local /regional control depot), notification signal by
DSO
Mandatory without
compensation (grid
connection rules defined in
grid codes)
Black start
Generation support in case
of islanding operation.
Back-up in testoration
processes of an area after an
outage.
Decentralized storage,
wind power, solar, small-
hydro power plants.
Availability of DG to start working (DGDSO).
Real-time generation output, maintenance periods, outages.
(DGDSO).
V, Q, pf setpoints (DSODG).
Mandatory with
compensation.
Table 8: System Services. Source: own and [7].
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5.4 Regulation of OPEX and CAPEX for DSOs
In this section, the main objective is to define the regulation method which best
incentivizes DSOs to implement service-based solutions wherever it is the most cost
effective solution.
5.4.1 CAPEX regulation.
Traditionally, DSOs capital expenditure mainly comes from the investment of new
reinforcements (repowering, new transformers, new lines, etc.). In other words, it can be
said that CAPEX of DSOs are “investment in copper”.
For the actual development of Smart Grids and the integration of the DER, DSOs need
to invest in:
Integration of ITCs: allow bidirectional information flow.
Creation of a market platform where DERs can offer system services.
Monitoring, simulation, control and forecasting tools for DSOs.
Therefore, it is necessary to incentivize DSOs in the investment of these three crucial
elements. Some of the initial investments required to establish these elements are:
CAPEX ITCs: smart meters, infrastructure to connect all agents, creation of data
hubs, etc.)
CAPEX market platform: software to co-ordinate this platforms, protocols for
communication between actuators, cyber-security, etc.
CAPEX tools for DSOs: software to build up each tool, necessary technology in
the networks to improve visibility, etc.
The method used to regulate the CAPEX of the DSOs should be an incentives based
regulation. Together with this regulation NRAs should define Key Performance
Indicators (KPIs) which take into the degree of implementation of new solutions.
Using incentives based regulation use good because:
NRA can control the gradual investments devoted to the integration of the new
solutions. In this way, NRA according to their energy policy can decide how
much money is dedicated to this purpose.
DSOs will make sure that the new investments are cost-effective in the long-
term planning of the network. At the same time, they will analyze when the
traditional investments in copper are better than investing in these new solutions.
Regarding the KPIs, they should be used as measures for NRA to control that
investments in this new solutions are being carried out when they are cost-effective in
the long-term planning.
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5.4.2 OPEX regulation.
Traditionally, DOS’s operation expenditures (OPEX) have been based in maintenance
of their networks. However, the implementations of ITCs, the creation of a market
platform and the new tools for DSOs enclose new OPEX that must be considered.
Some of these OPEX associated to each element could be:
OPEX ITCs: software updates, protocols improvements, maintenance of the
electronic devices, etc.
OPEX market platform: co-ordination of these markets, reparation of
communication problems, purchasing of the system services provided by DER, etc.
OPEX tools for DSOs: software updates, protocols improvements, maintenance of
devices that allow the well-functioning of these tools, etc.
As in the case of the CAPEX, the method proposed for the regulation of OPEX is an
incentives based regulation. At the same time, KPIs would be required, but in this
case the KPIs will be based in security, quality, efficiency and economic variables.
This regulation method allows the gradual operation of the new assets but together with
the KPIs, they will ensure that the most cost-effective solutions are taken without
threatening the security, quality and efficiency of the system.
5.5 Integration of DER into the market.
5.5.1 DG
Subsidies for immature DG technologies must chase the technical development with the
final aim of obtaining profitable technologies.
When designing the subsidies there are two factors that must be considered:
Maturity
Penetration into the system
Avoid high penetration of subsidised immature technology resulting in expensive
technology and instability for the system.
Method defined for providing the subsidies
According to the experience curve and the price of energy in the wholesale market:
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Figure 35: Difference between the cost of producing energy with a certain technology and the marginal
price of the wholesale market according to its experience curve.
There are two conclusions:
Subsidies must be decreasing on time otherwise it means that there is no technical
development and reduction of costs.
There must be a limitation of integration for each technology to allow the
implementation of next generations.
How to limit integration
In order to limit the number of project of a certain technology when they are still in
immature stages, regulatory authorities should:
Establish a total amount of money devoted for subsidies (in next section we analyse
from where this money should be withdraw).
Secondly, they should define what proportion is devoted to each technology. Here
we recommend to:
o Higher proportion for less immature technologies but less amount per
projectmore number of projectseconomies of scale.
o Lower proportion for more immature technology but more amount per
projectless number of project limiting its integration into the system.
From where should be obtained the money for subsidies:
The total amount of money can be withdrawn from two different sources:
Access tariff: this is the regulated part of the final costumer’s bill. To provide the
subsidies a small extra cost would be added. This would result in a higher cost of
electricity giving as a result a diminution of competitiveness of the country.
National State Budget: if the subsidies are related to the National State Budget
through the energy policy of the country, it would be charge to national population
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as taxes. This results in a reduction of purchasing power of the population,
impoverishing the country.
Hence, it can be concluded that subsidies are not good for a country in the short-term.
Therefore, subsidies should be reduced as much as possible.
Nonetheless, if the country wants to develop technologically and become more efficient
and competitive in the long-term, subsidies for development of new technologies
should not be totally eliminated
The final decision of deciding from where to get the money will depend on the:
economic situation and the energy policy of the country. Governments have the last
word about what is the most convenient decision.
5.5.2 Demand Response
In order to integrate demand response into the system, the following elements are
necessary:
De-regulated market-reflective products
Price signals
Smart meters
The shift from regulated contracts to de-regulated contracts must be voluntary. Final
customers are not expected to supervise the prices of each hour and even less, they will
think how to optimize their consumption. In order to obtain this shift, energy suppliers
must create products that adapt to final customers’ needs (industrial, service and
household consumer).
When products adapted to the necessities of each customer are created, final customer
will find more profitable these new products than the regulated ones.
Energy suppliers: product design for final customer
In order to create products that adapt to customers’ consumption habits, energy
suppliers should follow the following steps:
Firstly, energy suppliers must perform an analysis about the characteristics that define
final customers. In order to perform such analysis, energy suppliers need information
about consumption habits of final customers. This information should be provided by
DSOs, who gathered the information in data hubs using the smart meters.
The information exchange between DSOs and energy suppliers must be based on
regulatory rules, since DSOs are a regulated business. For this purpose, regulatory
authorities should:
Define what data from smart meters is commercial. Commercial data, is the data
that DSOs are able to provide to energy suppliers to design new products.
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Establish how often energy suppliers can demand final customers’ information
from DSOs.
Secondly, energy suppliers can define different segments according to decisive
characteristics. For instance: contracted power, level of consumption, period when the
energy is consumed, prosumers5, etc.).
Finally, energy suppliers must choose their position into the market, according to their
business model. Based on their business model, each supplier must create the products
that best suit their target customers. Here there will be a competence between energy
suppliers aiming at the same type of clients, resulting in a more competitive retail
market. The one who offer the best products (contracts) will gather more clients.
Alternatively, the possibility of energy suppliers to earn extra benefits from
participating in firm management markets, can motivate that some energy supplier
decide to partially focus on clients who are willing to change the normal consumption
habits in return of economic benefits.
Clients: Choosing the product that best suit their needs
Due to the fierce competence in the retail market, clients will benefit from contracts
which would bring benefits compared to the regulated ones. At the same time, clients
(industry, services and household consumption) will benefit from contracts that adapt to
their necessities (the cheapest service, the best quality service, the one who offers more
complementary services for the comfort at homes, etc.). This will avoid that clients
must be aware of price signal received on their smart meters every hour.
At this point it is important to highlight what is the role of automated houses and
smart appliances within the household consumption segment. The automated houses
can be referred to as a facilitator. Its main function is to automatically optimize the use
of electricity for the comfort conditions set by the customer.
Automated homes according to the local conditions in the house and the prerequisites of
clients, will automatically manage smart appliances and other equipment of the house to
maximize the use of the local resources.
5 Prosumer: consumers who export their excess of electricity to the market via local distribution network.
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6. Conclusions
The key conclusions for the implementation of the DER are:
1. Incentivize firmness of DG and DSP for the planning.
When considering firmness of DG, it is important to distinguish between two different
groups of technologies: dispatchable and non-dispatchable. The non-dispatchable
technologies (such as wind power or solar energy) need the technological development
of electrical storage technologies to be able to improve their firmness.
Additionally, to incentivize firmness of DG and Demand NRA should:
Create firm capacity management markets.
Define DSOs as market facilitators who co-ordinate these markets.
Allow commercial communications with DG, energy suppliers and large
customers.
Enable DSOs to receive information about the energy agreements established in
the wholesale markets.
Define ex-post payment of the firmness. Only when the DSOs use the firmness
of DG or demand, they have to pay for it.
Define the regulation used for the OPEX and the CAPEX required for the
creation of these markets.
2. DSOs must evolve towards an Active management approach.
This method for providing connection and access (non-firm connection and non-firm
access) of DG is the most cost-effective solution, being a trade-off between OPEX and
CAPEX.
3. Non-firm access contracts.
NRAs should allow DSOs to offer this type of contracts for DG in reward of economic
benefits such as shallower connection charges. These contracts allow DSOs to curtail
DG a limited number of hours in the year when congestions may appear in the network.
DSOs need to integrate new tools for monitoring, simulating, FALTA…to determine
the number of hours that curtailments could be required. A bad planning of these hours
can lead to problems higher expenses for DSOs.
Furthermore, NRA should define the criteria for the curtailment of DG connected in the
same point of the network. The criteria proposed in this dissertation are recommended.
4. Connection of DG.
Within the connection of the DG there are several aspects that need to be modified.
First, regarding the technical connection criteria:
NRA should define for each type of technology protection criteria based on
UNE or IEC standards. These criteria must provide stability to the system,
instead of disconnecting DG when the protections detect disturbances in the
network.
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NRA should allow DSOs to offer shallower connection charges (instead of deep
connection charges) in order to incentivize the DG provide system services that
support DSOs in the operation of their networks.
Secondly, for the integration of the DG in the wholesale markets and in the system
services markets, DG producers must implement ITCs that will enable the bidirectional
communication with DSOs. These ITCs will provide DSOs with useful information
(schedule, dispatching, outages periods, etc.) for the operation. The costs of the ITCs
should be shared between DSOs and DG.
Finally, NRA should
Reduce lead times and complexity of the authorization process for the
connection of DG to the network.
Define transparent and non-discriminatory criteria for all DG.
Create standardized connection criteria for the national territory.
5. Connection of the demand
The most important component in the connection of the demand is the smart meter. This
device together with the de-regulated contracts will result in a more elastic demand
introducing therefore the demand response.
The costs of smart meters should be shared between DSOs and final customers. This is
because smart meters will provide useful information (technical, static and commercial
data) which will improve the operation and planning of the DSOs.
6. Operation
The integration of the DER will require a more flexible operation system. For this
purpose NRAs should:
Define three different system states (normal, alert and emergency operation
state) according to the security state.
Create a system services market that will enable DSOs to control their networks
more actively and solve the problems of the system, coming back to the normal
operation state.
Define the necessary system services for each operation state. This system
services will be provided by DER and purchased by DSOs through commercial
arrangements (alert state) or directly used (emergency state) with posterior
compensations.
Establish DSOs as market facilitators, since they are the ones who better know
their own networks.
Define the necessary compensations for the emergency state.
Incentivize DSOs to invest in the creation of these markets(CAPEX) and their
operation (OPEX).
7. CAPEX and OPEX regulation: new investments of the DSOs
For the integration of the DER in the distribution networks, DSOs need to invest in:
Integration of ITCs.
Creation of system services market platform.
Monitoring, simulation, control and forecasting tools.
This new investments and their operation together with the system services that DSOs
will purchase in the system services markets, comprise new CAPEX and OPEX.
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NRA should develop an incentives based regulation together with KPIs which take into
account the quality, security, efficiency, level of integration of new solutions and
economic variables. This will allow NRA to control the gradual integration of the new
solutions at the same time that avoiding overinvestments and the threat of DSOs’ tasks.
8. Integration process of new DG technologies in the system.
The subsidies for the integration of new technology in DG should be done in a way that
incentivizes the technological development, becoming more competitive at the same
time that limiting the integration of high shares of immature DG in the system.
For this purpose, NRAs should first establish a fix amount of total subsidies that they
want to dedicate for this purpose. Then, in order to limit immature technology and its
development NRA have should follow the following criterion to share the subsidies:
Higher proportion of the total amount of subsidies for more mature technologies,
but this money will be divided among many projects.
For less mature technologies, a smaller proportion of the total budget should be
devoted for them, but the money will be divided among few projects. NRAs
have to decide according to their energy policy whether the subsidies are
withdrawn from the access tariff or the National State budget.
Finally, NRAs have to decide according to their energy policy where do they obtain the
money from. There are two possible options:
Access tariff: this would result in a higher cost of the electricity and therefore a
diminution of the competitiveness on the country.
National State Budget: this option provokes the reduction of the purchasing
power of the population.
Any of the options has negative effects, but a better efficiency of the electrical system in
the long-term time scale can be only achieve by investments on new technologies which
are expected to be cost effective.
9. Integration of the Demand Response
For the integration of the demand response in the electrical markets there are two
components which are crucial:
Price signals through smart meters.
De-regulated contracts.
Final customers are not going to be checking the price of the electricity for each hour of
the day and try to optimize their consumption over the day. Because of this, it is
essential that energy suppliers define attractive products that adjust to their target
customer consumption habits. This new contracts have to be good enough so that final
customer voluntarily shift from regulated contracts to de-regulated contracts.
Additionally, demand response requires that final customer receives price signals from
their energy suppliers (those final clients who agree contracts with energy suppliers) or
from the wholesale market (final customer who purchase the electricity directly from
the wholesale market). Additionally, end-users can obtain potential benefits in their
electricity bills if they decide to shift their consumption to those hours with lower
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energy market prices or when the system requires it (incentives from firm demand
capacity markets).
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