Deliverable 5 - NETfficientnetfficient-project.eu/wp-content/uploads/2018/01/D5.14... ·...

Project funded by the European Union’s Horizon 2020 research and innovation programme

Project No. 646463

Project acronym: NETfficient

Project title:

Energy and economic efficiency for today’s smart communities through integrated multi storage technologies

Programme: H2020-LCE-2014-3

Start date of project: 01.01.2015

Duration: 48 months

Deliverable 5.14 Regulation analysis and barriers identification report

Author: Fraunhofer Institute for Solar Energy Systems ISE

Due date of deliverable: 31/12/2017 Actual submission date: 20/12/2017

Deliverable Name Deliverable Number D5.14

Work Package WP 5

Associated Task

Covered Period M24-M36

Due Date M36

Completion Date M36

Submission Date M36

Deliverable Lead Partner Fraunhofer ISE

Deliverable Author Raphael Hollinger

Version 1.2

Dissemination Level

PU Public X

PP Restricted to other programme participants (including the Commission Services)

RE Restricted to a group specified by the consortium (including the Commission Services)

CO Confidential, only for members of the consortium (including the Commission Services)

Ref. Ares(2017)6248505 - 20/12/2017

D5.14 - Regulation analysis and barriers identification report Version 1.2

© NETfficient consortium Page | 2 Confidential document

CHANGE CONTROL

DOCUMENT HISTORY

Version Date Change History Author(s) Organisation

0.1 1.10.17 Document drafted Thomas Erge, Agustín Motte Cortés, Raphael Hollinger

Fraunhofer ISE

1.0 1.12.17 Document for consortium

See 0.1, with input from consortium (esp. AYESA and SWEREA)

Fraunhofer ISE

1.1 14.12.17 Document for Coordinator


Fraunhofer ISE

1.2 19.12.17 Document for submission


Fraunhofer ISE

DISTRIBUTION LIST

Date Issue Group

04.12.17 **Revision** **all partners**

11.12.17 **Acceptance** **Coordinator**, **WP leader**,**all partners**,

20.12.17 **Submission** **Coordinator**, **WP leader**,**all partners**,



Table of content

Table of content ................................................................................................................ 3

Index of Abbreviations ...................................................................................................... 6

1. Introduction ............................................................................................................ 8

2. Approach for Regulation Analysis ............................................................................ 9

2.1 Purposes for Regulation Analysis ................................................................................... 9

2.2 Regulation and Stakeholders........................................................................................ 11

2.3 Main Regulation Issues ................................................................................................ 12

3. Regulation Frameworks and Market Rules ..............................................................13

3.1 Energy Spot Markets .................................................................................................... 13 3.1.1 Description of Purpose ...................................................................................................... 13 3.1.2 Electricity Market Design in Europe .................................................................................. 13 3.1.3 Day Ahead Market (Germany) ........................................................................................... 17 3.1.4 Day Ahead Market (Spain) ................................................................................................. 18 3.1.5 Day Ahead Market (Sweden) ............................................................................................. 19 3.1.6 Day Ahead Market (UK) ..................................................................................................... 20

3.2 Balancing Power Reserve Markets ............................................................................... 21 3.2.1 Description of Purpose ...................................................................................................... 21 3.2.2 EU Regulation and Rules for Procurement ........................................................................ 25 3.2.3 National Regulation (Germany) ......................................................................................... 28

3.2.3.1 Primary Control Service ............................................................................................. 29 3.2.3.2 Secondary Control Service ......................................................................................... 32 3.2.3.3 Tertiary Control Service ............................................................................................. 33 3.2.3.4 Imbalance Settlement ............................................................................................... 35

3.2.4 National Regulation (Spain) ............................................................................................... 36 3.2.4.1 Primary Control Service ............................................................................................. 37 3.2.4.2 Secondary Control Service ......................................................................................... 37 3.2.4.3 Tertiary Control Service ............................................................................................. 38 3.2.4.4 Imbalance Settlement ............................................................................................... 39

3.2.5 National Regulation (Sweden) ........................................................................................... 40 3.2.5.1 Primary Control Service ............................................................................................. 42 3.2.5.2 Secondary Control Service ......................................................................................... 45 3.2.5.3 Imbalance Settlement ............................................................................................... 47

3.2.6 National Regulation (UK) ................................................................................................... 48 3.2.6.1 Primary Control Service ............................................................................................. 50 3.2.6.1 Tertiary Control Service ............................................................................................. 55 3.2.6.2 Imbalance Settlement ............................................................................................... 57

3.3 Peak Shaving and Local Grid Services ........................................................................... 57 3.3.1 Description of Purpose ...................................................................................................... 57 3.3.2 EU Regulation and Rules for Procurement ........................................................................ 60 3.3.3 National Aspects of Services (Germany) ........................................................................... 60

3.3.3.1 Reduction of grid charges .......................................................................................... 60 3.3.3.2 Curtailment minimization .......................................................................................... 64 3.3.3.3 Other Grid Services .................................................................................................... 65



3.3.4 National Aspects of Services (Spain) ................................................................................. 66 3.3.4.1 Reduction of grid charges .......................................................................................... 67 3.3.4.2 Curtailment minimization .......................................................................................... 67 3.3.4.3 Other grid services..................................................................................................... 67

3.3.5 National Aspects of Services (Sweden) ............................................................................. 68 3.3.5.1 Reduction of grid charges .......................................................................................... 68 3.3.5.2 Curtailment minimization .......................................................................................... 68 3.3.5.3 Other grid services..................................................................................................... 68

3.3.6 National Aspects of Services (UK)...................................................................................... 69 3.3.6.1 Reduction of grid charges .......................................................................................... 69 3.3.6.2 Curtailment minimization .......................................................................................... 70 3.3.6.3 Other grid services..................................................................................................... 70

3.4 Self-sufficiency and home energy supply ...................................................................... 72 3.4.1 Description of Purpose ...................................................................................................... 72 3.4.2 EU Regulation and Rules for Procurement ........................................................................ 75 3.4.3 National Regulation (Germany) ......................................................................................... 76

3.4.3.1 Contractual and legal aspects.................................................................................... 76 3.4.3.2 Revenues and Charges .............................................................................................. 77 3.4.3.3 Metering and billing .................................................................................................. 77 3.4.3.4 Other aspects ............................................................................................................ 78

3.4.4 National Regulation (Spain) ............................................................................................... 79 3.4.4.1 Contractual and legal aspects.................................................................................... 79 3.4.4.2 Metering and billing .................................................................................................. 80 3.4.4.3 Other aspects ............................................................................................................ 82

3.4.5 National Regulation (Sweden) ........................................................................................... 83 3.4.5.1 Contractual and legal aspects.................................................................................... 83 3.4.5.2 Metering and billing .................................................................................................. 83 3.4.5.3 Other aspects ............................................................................................................ 83

3.4.6 National Regulation (UK) ................................................................................................... 84 3.4.6.1 Contractual and legal aspects.................................................................................... 84 3.4.6.2 Metering and billing .................................................................................................. 84 3.4.6.3 Other aspects ............................................................................................................ 85

3.5 Building integration ..................................................................................................... 85 3.5.1 Description of purpose ...................................................................................................... 85 3.5.2 EU Regulation and Rules for Procurement ........................................................................ 87 3.5.3 National Regulation (Germany) ......................................................................................... 88

3.5.3.1 Tenants’ electricity supply concepts (general) .......................................................... 88 3.5.3.2 Metering aspects ....................................................................................................... 90 3.5.3.3 Legal requirements .................................................................................................... 90 3.5.3.4 Building connection to the grid ................................................................................. 92

3.5.4 National Regulation (Spain) ............................................................................................... 92 3.5.5 National Regulation (Sweden) ........................................................................................... 94 3.5.6 National Regulation (UK) ................................................................................................... 94

4. Important Regulatory Aspects for the Use Cases .....................................................95

4.1 Use Case 1: MV-HESS ................................................................................................... 95

4.2 Use Case 2: Homes....................................................................................................... 96

4.3 Use Case 3: Buildings ................................................................................................... 98

4.4 Use Case 4: Storage for Street Lighting ......................................................................... 99



4.5 Use Case 5: Thermal Storage Solution for low-temperature Large Volume Heating Requirements ........................................................................................................................ 100

5. References ............................................................................................................ 101

Annexes ......................................................................................................................... 113

Disclaimer:

This project has been funded with support from the European Commission.

This report reflects the views only of the authors, and the Commission cannot be held responsible for

any use which may be made of the information contained therein.

While we endeavoured to publish information up to date and correct, we make no representations or

warranties of any kind, express or implied, about the completeness and accuracy of information given

in the report. Any reliance you place on such information is therefore strictly at your own risk.



Index of Abbreviations

ACER Agency for the Cooperation of Energy Regulators

AGC Automatic Generation control

BESS Battery Energy Storage Systems

BIPV Building Integrated PV

BM Balancing Mechanism

BMU Balancing Mechanism Unit

BRP Balance Responsible Party

CE Continental Europe

CHP Combined Heat and Power

CSS Central Clearing System

DEGOF Degrees of Freedom

DG Distributed Generation

DSO Distributed Grid Operator

ECC European Clearing AG

EEG ger. Erneuerbare Energie Gesetzt (German Renewable Energy Act)

EEX European Energy Exchange

EFR Enhanced Frequency Response

EIC Energy Identification Code

EnEV ger. Energiesparverordung (Energy Efficiency Regulation)

EnWG ger. Energiewirtschaftsgesetz (German Energy Industry Act)

EPEX SPOT European Power Exchange

ETS EPEX Trading Systems

EV Electric Vehicles

FCDM Frequency Control by Demand Management

FCR Frequency Containment Reserve

FCR-D Frequency Containment Reserve – Disturbance

FCR-N Frequency Containment Reserve – Normal

FFR Firm Frequency Response

FiP Feed-in Premium

FiT Feed-in Tariff

FRR Frequency Restoration Reserve

FRR-A Automatic Frequency Restoration Reserves

FRR-M Manual Frequency Restoration Reserves

HESS Hybrid Energy Storage Systems

HVDC High Voltage Direct Current

ICE Intercontinental Exchange

ICT Information and Communications Technology



IEA International Energy Agency

IEA PVPS IEA Photovoltaics

IGD Implementation Guidance Document

JAO Joint Allocation Office

LCOE Levelized Cost of Electricity

LFC Load-Frequency Control

MARI Manually Activated Reserves Initiative

MFR Mandatory Frequency Response

MIBEL esp. Mercado Ibérico de la Electricidad (Iberian Electricity Market)

OMIE esp. Operador del Mercado Ibérico de Energía - Polo Español (Iberian Energy Market Operator – Spanish Pole)

OTC Over-the-Counter

PCR Price Coupling of Regions

PCR Primary Control Reserve

PPA Power Purchase Agreement

PSH Primary, Secondary and High Response

PX Power Exchanges

RAIPEE Administrative Record of Electric Energy Production Facilities

RCP Peninsular Shared Regulation

RES Renewable Energy Sources

RoCoF Rate of Change of Frequency

RR Replacement Reserve

SCR Secondary Control Reserve

SO System Operator

SoC State of Charge

SSB System Buy Price

SSP System Sell Price

STOR Short Term Operating Reserve

TAR ger. Technische Anschlussregeln (Technical Connection Rules)

TCR Tertiary Control Reserve

TERRE Trans European Replacement Reserves Exchange

TSO Transmission Grid Operator

VAT Value-added Tax

D5.14 - Regulation analysis and barriers identification report

Version 1.2


1. Introduction

Integration of smart storage systems into smart grids and smart communities is the key focus of the

project NETfficient. The development of technical solutions for the components, operation

management systems and control strategies certainly is the inevitable foundation of smart storage

system integration. Yet even the most mature technical solution will fail in practice if it is non-

compliant to the framework of legal and regulatory issues it is exposed to. There are two alternative

ways to resolve such conflicts: either adopt the technical solutions to the regulation or adopt the

regulation to the technical solution.

The NETfficient project intends to consider both possibilities. First it will identify and describe the

existing framework of regulations in representative EC countries and specify requirements for a

number of business services that could be offered by the innovative storage systems developed

within the project. This knowledge is convolved with the (technical) methodology to be applied for

different business cases for smart storage systems, and conflicts or inadequacies will become visible.

Knowledge about these conflicts will be used to either give recommendations regarding the technical

solution (e.g. asking to change technical parameters) or to develop recommendations for an

adaptation of the regulation framework itself. Because of the profound chances linked to the current

transition process in the energy supply systems (including a complete revision of the energy supply

architecture changing from centralized to decentralized supply structures) it can be assumed that a

number of innovative technical solutions could not be implement under the current regulatory or

legal schemes.

As a first step, Task 5.9 of the NETfficient project summarizes the regulatory requirements for

innovative business opportunities for smart storage systems and identifies first barriers hampering

the implementation of technologically mature solutions. It focuses on the use cases defined in the

project work plan, emphasizing matters of ancillary services, battery integration into home energy

supply system, battery integration into buildings and general use of electrical storage systems for

urban electrical or (indirectly) thermal supply tasks. This Deliverable 5.14 summarized the findings

and working results.

The project team decided to select a number of typical European countries for more detailed analysis

(Germany, Spain, Sweden and the UK). Certainly the situation in Germany will receive special

attention because of the actual implementation of smart storage systems within the project at the

field test in Borkum.

Even though the country selection was partly driven by representation in the consortium this

selection represents a good mix of differing local framework conditions and geographic distribution.

Because of the progressing harmonization of European standardization findings from the

investigation of those countries are mostly also representative for the situation in other EC countries.

It should be mentioned in this context that currently legal and regulatory requirements related to the

energy supply and transport systems are subject of a lively revisions and literally each day some rules

or standards in some EC countries are changing. If possible this document will reflect such revision

processes but certainly some details will have been changed the day the deliverable is published.

Therefore, readers should cross-check technical details with the original resources quoted if being

needed for practical purpose.


Version 1.2


2. Approach for Regulation Analysis

In this Chapter the goal and the focusing of collecting information about European regulation

frameworks and market rules relevant for small and medium size energy storage technology is

described. Starting point for this analysis are “purposes” or “functionalities” for the smart storage

systems being the generic technical starting point for building up business models later on.

2.1 Purposes for Regulation Analysis

A number of “purposes” have been defined during the preparation of the project proposal for the

NETfficient project. Table 1 shows those purposes with a prioritization of purposes most relevant for

the project context.

In order to avoid confusion about the terminology and intentions a short explanation for the most

relevant “purposes” is given below. Some more details will be give later on when discussion the

regulation frameworks of the different EU countries. In addition to the purposes shown in the table

day-ahead power markets will be considered as well, since storage systems might play an important

role regarding the levelling out of imbalances between offered generation and requested demand on

the power markets and could make use of price variation on the market.

Table 1: Purposes identified for storage systems by the NETfficient consortium. Source: project proposal


Version 1.2


Besides those “purpose” driven aspects the regulation analysis will also give reference to general

storage regulation matters which have been previously identified and discussed in the BRIDGE

Regulations Working Group. These can be found in the First Annual Report dated January 2017.

Energy spot markets

Spot markets are, generally speaking, public financial markets for the exchange of financial

instruments or commodities. In relation to the commodity “energy” the term “spot market” mostly

refers to a bundle of predefined products involving the trading and finally physical delivery of a

certain amount of energy (power) during a certain time period. Typical trading periods are day-ahead

to 15min ahead to physical delivery. Long-term contracts (one week and above) belong to the futures

market and often serve for collateralisation or hedging purposes. Only spot markets will be

considered in the present report.

Balancing power reserve markets and synthetic inertia

In order to guarantee the functionality of power plants and electric appliances the frequency of the

synchronous system has to be regulated at 50 Hz within tight limits. Any imbalance between

generation and demand causes a frequency gradient that is corrected by the so called Load-

Frequency Control (LFC) which is based on a concept of power reserves operating on different time

scales (Figure 1). Imbalances may originate from deviations between forecasted and actual

generation as well as load, forced power plant outages or failures of grid components resulting in a

sudden disconnection of generation or load units. The grid operators are obliged to procure and have

available sufficient power reserves. Note that such power reserves are procured for larger grid

sections (like a whole national grid) and need not be located near the spot of occurrence of the

frequency deviation.

In most EU counties open and transparent markets exist for trading products related to those power

reserves. The present working report will only address short-term power reserves (up to 1 hour),

long term power reserves are of no relevance in the present context.

Figure 1: Frequency deviations in the power grid lead to a cascade system of the activation of power reserves depending on the duration of the disturbance (incite)


Version 1.2


Peak shaving and local grid services

Different from wide-are aspects of power supply, peak shaving and local grid services address the

local power quality and stress in (mostly) distribution grids. From the perspective of the distribution

grid operator (DSO) the infrastructure of the grid (cables, transformers, etc.) must be sized properly

to bear the maximum expected loads. The same applies to the local infrastructure of house and

building owners. Peak shaving and smart grid services (like the local injection of reactive power)

allow lowering the peaks of load flows and stress on grid components, respectively. Since frequently

electricity tariffs are a combination of a power and an energy price component, lowering the

maximum power demand might lead to a significant reduction of monthly paid electricity bills. Also

for generation units peak shaving might be relevant, starting with costs for necessary grid

reinforcement measures and also involving situations where a limitation of feed-in peaks is required

by law.

Local grid services considered in the current working paper are a change in load and generation

power following a request by the DSO and aspects of the provision of reactive power.

Self-sufficiency and home energy supply

Except of cases with high feed-in tariffs, local consumption of locally produced electricity significantly

lowers the expenses for energy supply and amortization of the investment. Battery systems offer

excellent opportunities to increase the volume of locally consumed electricity and thus help

increasing self-consumption and self-sufficiency. Even though self-consumption (the intention to use

as much as possible of energy produced locally) and self-sufficiency (the intention to cover most the

own energy need by own generation) are two different concepts, they will be discussed jointly

because of basically the same technical strategy.

Building integration

For the use case “building integration” certainly self-consumption and self-sufficiency are relevant

concepts too. Different from “simple” home energy supply systems it should be assumed that

batteries in buildings are integrated into a larger, multivalent building energy management system

and generators/storage systems are often owned and operated by third parties. These aspects lead

to some specific regulatory aspects and additional business concepts that will be discussed under this

topic.

2.2 Regulation and Stakeholders

Talking about “regulation”, this concept means the definition of some laws, rules and orders by

authorities to be followed (mostly mandatory) by either (in the transferred sense) “humans” or

“technical devices”. For instance, some regulation might forbid the participation of some

businessmen to sell electricity at the power markets (because he is not trained to do so) or it might

forbid the sale of energy at the power market from some technical device, because this device is not

able to meet basic technical requirements.

Therefore investigating regulation issues always involves consideration of technical standards and

consideration of special stakeholder requirements and situations. For the business models to be

developed in the NETfficient project quite a number of different stakeholders might become

involved:

Consumers and final customers

Network users

DSO, TSO


Version 1.2


Equipment manufacturers and industry

Traders

Energy suppliers

Energy service providers

Information and Communications Technology (ICT) providers

Regulation bodies and decision makers

It is very likely that some of the future business models require the “redesign” of the role and the

competences for some of the stakeholders. One simple example for this:

Currently detailed data from Smart Metering systems installed at the premises of small end users are

collected by meter operators or the responsible DSO. Data protection laws of today prohibit the

transfer of those data to third parties without special arrangements (even to the grid management

unit of the DSO!). Yet business models utilizing home storage systems are in urgent need of detailed

load and operation data from the field and therefore would strongly benefit, if the meter operators /

DSO would play the role of some “Middleware” between the single storage units in the field and the

aggregated marketing of smart grid services by the Energy Services Company (ESCO).

2.3 Main Regulation Issues

Major regulation issues related to relevant business cases have been identified within the work of Work Package 1 (adopted from (AYESA ADVANCED TECHNOLOGIES, 2015)):

1. Regulations that might hinder storage valorisation 2. New services/New regulations 3. Safety issues 4. Network code 5. Legal framework covering energy exchange between different parties 6. Regulation covering the warranty of the batteries and the guaranty of the service delivered 7. Environmental issues 8. Ownership of the batteries 9. Flexible regulatory framework for special cases (e.g. demonstration sites)

The collection of data and requirements for different “purposes” presented in the next paragraphs

will take those regulation categories into account. It should be noticed, however, that only a part of

those regulation issues is specific for “smart storages in smart grids” and lots of the regulations have

a more general scope addressing large classes of devices. In the present case of this Deliverable we

will focus on such regulatory issues which are clearly linked to our specific use or business cases and

leave out all matters of general importance (e.g. the general requirements on how to install electric

devices in customers’ homes).


Version 1.2


3. Regulation Frameworks and Market Rules

Detailed information about the most relevant regulation frameworks and market rules is given in this

Chapter, mainly clustered by the “purpose” for the corresponding use cases. For this goal, a short

introduction into the different types of purposes is given, followed by detailed information about

regulatory and legal frameworks. For purposes with a high level of standardization in the EU

countries, the description will be given as a more general description mentioning some national

peculiarities. On the other hand, country-specific aspects will be discussed individually.

3.1 Energy Spot Markets

3.1.1 Description of Purpose

Spot markets for electricity are transparent and open trading platforms allowing market participants

to offer and purchase several kinds of electricity products. They include long-term trading and short

term trading products as well as derivate products. Even though only a part of the daily energy trades

is transacted via the spot markets (most electricity is traded via Over-the-Counter (OTC) contracts),

the price building mechanisms at the spot market determine the general price for energy trading.

Different to OTC, trading spot markets also act as clearing agencies, thus alleviating the risk for

payment defaults of trading partners.

3.1.2 Electricity Market Design in Europe

Up to about 30 years ago, monopoly-like large companies being subject to regulatory prescriptions of

the national governments dominated the electricity sector in the EU countries. Today, most of the

electricity companies in Europe are vertically unbundled following three legislative packages of the

European Union (1996, 2003 and 2009), gradually opening the energy sector for competition and

aiming at a European energy market. This transition process is still not accomplished and there are

different national market designs existing. When talking about energy markets, one should bear in

mind that (large) energy generators compete in the wholesale electricity market, while suppliers

selling electricity to final consumers will act in the retail electricity market. In the current chapter,

only the wholesale electricity market will be considered, while capacity markets will be ignored.

There are two types of wholesale electricity markets:

• Power exchanges (PX) or multilateral trading platforms

• Bilateral OTC trading

While in OTC trading the participants are free to submit/accept individual prices for their products,

multilateral trading platforms define a price-building process leading to representative market

process for certain standardized market products. In the context of evaluating business concepts

such market prices allow the evaluation of the potential profitability of different business

approaches.

Since electricity delivery and consumption must be balanced instantaneously, the electricity markets

are sequentially organized to deal with this property. The responsibility of maintaining this balance

lies with the TSO. Before delivery, the balancing responsibility lies with the Balance Responsible

Parties (BRPs), which is a private legal entity which represents generators, suppliers and/or industrial

consumers. BRPs seek to balance their own portfolio and are able to trade electricity with other BRPs

to do so.


Version 1.2


Large market platforms often offer a portfolio of different services and products, reaching from long-

term products in the “forward and future market”, products marketed in the upcoming hours to

physical delivery day in the “day-ahead market” and short-term products in the “intraday market”.

These products are marketer either by means of an auction, continuous trading of contracts or both.

A BRP portfolio may still be in imbalance after intra-day market, after gate closure, the system

operator takes balancing actions by activating reserve power (see section 3.2.1). After physical

delivery and the metering of electricity volumes from activated reserves the imbalance settlement

for BRP’s takes place. Figure 2 shows the sequence of the previously mentioned markets.

Figure 2: Sequence of trading at the energy markets. Source: (KU Leuven Energy Institute, 2015)

Forward and future markets are mostly used by market participants to reduce the risk of rapidly

changing energy prices and often contracts are not fulfilled physically. The cross-border trading of

future products requires the parallel provision of transmission capacities, which in Europe is

organised via the Joint Allocation Office (JAO).

The day-ahead market is where most of the volume handled by markets is traded in order to

accomplish a balance between generation and demand. One typical feature of the day-ahead

markets is the auctions taking place at a specific time of a day concentrating the liquidity and

allowing the determination of reliable reference prices. The physical delivery of the power quantities

takes place on the following day. Because of the transparent price building mechanisms, the prices at

the power exchanges are representative for all day-ahead electricity trading. Typically, there are

market zones covered by the different EU market places. Figure 3 shows the volumes of different

energy products for a selection of EU market zones. More detailed data are published regularly by

the EC in the “Quarterly Reports on European Electricity Markets” (European Commission, 2017).


Version 1.2


Figure 3: Comparison of electricity traded volumes in some important day-ahead, forward and OTC markets, third quarter of 2016. Source: (European Commission, 2016)

There is a continuous process of coupling the prices of day-ahead markets, for example by means of

day-ahead implicit auctions. That means that cross-zonal capacity is allocated implicitly with the

matching of the most competitive energy bids and offers. This process of growing together is based

on the harmonisation of the applicable codes, like connection codes (requirements for large

generators, customers, HVDC-lines), operational codes (TSOs responsibilities) and market codes.

Figure 4 shows the status of EU market coupling of the day-ahead markets.

The Price Coupling of Regions (PCR) is an initiative of seven European power exchanges (EPEX SPOT,

GME, Nord Pool, OMIE, OPCOM, OTE and TGE) to harmonize electricity markets through a single

price coupling algorithm called EUPHEMIA, which is used to calculate electricity prices across Europe.

Figure 4: Price Coupling of Regions members, associate and potential new members

Except the aspect of market coupling there are no EU regulations relevant for operators of storage

systems participating in the day-ahead energy markets (being the focus in this working document).

Nevertheless, there are some common requirements for actors wanting to sell or buy electricity at

the EU spot markets. First of all, a decision has to be made whether an actor wants to trade


Version 1.2


electricity at the spot market himself. In that case, a number of formal requirements have to be met,

such as:

Allocation to a BRP (a trader needs to have a contract with an existing BRP or establish a

new one)

Accreditation from the PX (in order to be accredited the trading company has to prove the

qualification and reliability and financial securities)

Admission as a trading participant (typically provided by the institution that performs the

financial clearing for the PX – the clearing house)

If one does not want to become active market participant, selling and purchasing electricity at the

stock market requires commissioning of some service provider, leading to additional costs.

Aggregators in Electricity Markets

While providing services for all kinds of electricity consumers which own generation and storage

units, aggregators can offer value to actors such as BRPs, DSOs and TSOs in form of balancing and

congestion management. A more in-depth analysis of technical, legal and regulatory barriers for

renewable energy aggregators in the EU is provided by the currently running BestRES project, which

focuses on the implementation of business models for renewable energy aggregators in Austria,

Belgium, Germany, France, Italy, Cyprus, Portugal, Spain and the United Kingdom (Pause & Wizinger,

2016).

In the barrier identification document for the BestRES project (Pause & Wizinger, 2016) it is

remarked that the existing EU regulation is not sufficiently differentiated. In spite of the aggregators

being accepted as market participants, there is no aggregator-specific regulation and the formal

definition of “aggregator” in the Energy Efficiency Directive just considers the demand side but not

the generation side. The resulting barriers study is summarized in Figure 5.

Figure 5: Barriers for optimal deployment and operation of current business models for renewable energy aggregators (Pause & Wizinger, 2016)


Version 1.2


Peer-2-Peer Energy Trading

The increasing decentralization of energy generation has given rise to the so-called “Peer-2-Peer

Energy Trading”. The actors involved are prosumers, which generate and consume their own

electricity and are also able to store surplus energy and sell it locally to other prosumers or

consumers, which have an energy deficit. Different business models involve a trading platform with

an agent acting similar to a supplier or are focused on ICT systems for Microgrids. Some examples of

existing trading projects include SonnenCommunity and Lichtblick Swarm Energy in Germany or Piclo

in the UK (Zahng, Wu, Long, & Cheng, 2016).

Another developing application is the Enerchain p2p trading tool, developed by the software

company Ponton, which implements local energy trade over the blockchain. Currently 22 European

trading firms take part on the Enerchain project (Ponton, 2017). The scale and speed of

implementation of the blockchain is still uncertain but it may prove an accelerator for the

development of P2P energy trading.

The EU P2P-smarTest project has identified regulatory barriers for the implementation of Peer-2-

Peer energy trading (Li, et al., 2016). The consortium used the Finnish example to present the

European case. Barriers identified include the transparency of regulation, legislation and rules

regarding government supports, and data security and privacy.

3.1.3 Day Ahead Market (Germany)

The German trading platform for day-ahead electricity is the European Power Exchange SE (EPEX

SPOT SE), an exchange for power spot trading in Germany, France, Austria Switzerland and

Luxembourg. It is hold by the European Energy Exchange (EEX) Group and Transmission System

Owners. EPEX SPOT runs two markets: the “day-ahead market” with hourly day-ahead auctions and

the “intraday market” with continuous intraday trading and a 15-minute intraday call auction. Hourly

day-ahead auctions at the EPEX SPOT have the following basic features (European Power Exchange

EPEX SPOT, 2017):

Auction hours: at 12.00 pm, 7 days a week, year-round

Publication of results as soon as possible from 12:42 pm

24 hours of the following day are traded

Price must be between -500 €/MWh to 3.000 €/MWh

Hourly and block contracts available for trading

Multiregional price coupling

Price Thresholds to trigger a second auction: -150 €/MWh (lower threshold), 1500 €/MWh

(upper threshold)

Each participant can submit a number of price-volume-combinations for each hour of the

upcoming day

All products traded on EPEX SPOT are cleared and settled by the European Clearing AG (ECC)

Some technical and legal requirements for participation shown in the following table:


Version 1.2


Table 2: Technical and legal requirements for direct participation in the German spot market

Technical requirements Legal requirements

0.1 MWh least bid size (i.e. 0.1 MW for 1 h) Allocation to balancing area in one of the TSOs

regulating areas

0.1 MWh increment 50 000 € equity capital

Connection to EPEX trading systems (ETS) (either ETS web access via internet or ETS API)

Accreditation as clearing/non-clearing member by ECC (securities required)

¼ h power metering (standard) for trading at EPEX

Reliable and professional qualification of trader and CEO

Non-monotonous single-contract orders are forbidden

Maximum volume for a block bid: 600 MW, maximum 100 block bid per trading account

A list of prices for fees and transactions can always be found at the EPEX SPOT download centre

(EPEX SPOT, 2017b).

Demand Response Aggregators

In terms of aggregation, day-ahead and intra-day markets are open for final consumers through their

electricity retailer (BRP) through implicit and explicit Demand Response. However independent

Demand Response Aggregators are unable to do so. Although there is no specific regulation

prohibiting Demand Response from participating, there is a lack of standardized processes, network

tariff design discouraging consumers from participating and low market prices. There is also no

framework in place, which defines interactions between the energy retailer and independent third-

party aggregators (Smart Energy Demand Coalition - SEDC, 2017).

3.1.4 Day Ahead Market (Spain)

The Iberian Energy Market Operator – Spanish Pole (OMIE) is regulated by the “Santiago

International Agreement”, regarding the implementation of an Iberian electricity market (MIBEL)

between Spain and Portugal, and subject to the rules and regulations governing Spain’s electricity

sector. OMIE manages the Day Ahead and Intraday Markets, while the forward energy trade is

managed by the Iberian Energy Market Operator – Portuguese Pole (OMIP). Since May 2013, the

MIBEL day-ahead market is coupled with prices in Europe, utilising the EUPHEMIA algorithm to

calculate electricity prices. Some of the characteristics of this market include:

There are over 800 market agents participating

The market has a shorter range of prices compared to other markets in Europe such as Nord

Pool or EPEX SPOT. Price range: (0-113.92) €/MWh. Average price: 42 €/MWh. Standard

deviation: 19 €/MWh.

Gate closure is 10.00 am on the day before supply and clearing prices are published at 11:00

am

The auction takes place once a day; at 12pm the auction is conducted for the 24 hours of the

next day.

Market rules oblige generators to offer the complete available capacity across the sequence

of markets


Version 1.2


Market-splitting is used to set the electricity price on the day-ahead market in Spain and

Portugal

More information on the functioning of the electricity markets found in the “Description of the

operation of the MIBEL” (MIBEL Regulatory Council, 2009) as well as in (Frontier Economics, 2016).


At the moment, there is no possibility for aggregated demand-side resources to take part in the

Spanish electricity market. There is no concept of aggregator for Demand Response nor there are

standards defining their relationship with the BRP and the TSO. There is however, the role of

“representatives”, which sell energy in the name of their “representees” and support minimising

deviations from the programme through balancing (Smart Energy Demand Coalition - SEDC, 2017).

3.1.5 Day Ahead Market (Sweden)

The Day Ahead Market in Sweden is provided by Nord Pool Spot AS. Nord Pool is one major power

market in Europe, offering both day-ahead (Elspot) and intraday markets (Elbas). It serves the Nordic

countries Norway, Denmark, Sweden and Finland as well as Estonia, Latvia and Lithuania.

Additionally Nord Pool Spot fully operates the UK power market N2EX.

Elspot is the day-ahead auction market in Nord Pool, where around 360 market members participate

placing a total of around 2000 orders for power contracts daily. The power market is divided in

bidding areas (see Figure 6), which help to reflect constraints in transmission in the electricity price

(Nord Pool, 2017). Nord Pool calculates prices for each of the bidding areas for each hour of the

following day. Due to congestion in the transmission system, these areas may get different prices.

When there is congestion between two bidding areas, the power flows from the low price area to the

high price area, where the demand is higher.

Day-ahead product specification for Nordic, Baltic and German market areas (Nord Pool, 2017b):

Gate closure is at 12:00 CET and hourly prices are announced at 12:42 CET or later

Physical delivery starts from 00:00 the next day according to the contracts agreed

Orders may be submitted in Euro, NOK, SEK, DKK. Price calculation in Euro

Block Order Volume Limit: 500 MW

Trade lot: 0.1 MW

Lower technical Order Price Limit: Euro -500. SEK -6500.

Upper technical Order Price Limit: Euro +3000. SEK +39000.

More information can be found in “Rules and Regulations” documentation in Nord Pool’s website

(Nord Pool, 2017a).


Version 1.2


Figure 6: Nord Pool bidding areas. Source: (Nord Pool, 2017)


Demand response participation and aggregation of demand-side resources are legally possible in

Sweden although it is currently not possible to have a clear view of the size of its participation in the

Nord Pool Market. An independent third-party aggregator needs to be a BRP and obtain a

contractual agreement from consumers’ retailer/BRP to participate in the market, hampering the

market potential of demand-side resources (Smart Energy Demand Coalition - SEDC, 2017).

3.1.6 Day Ahead Market (UK)

There are many products and platforms available to trade power in Great Britain. Even though OTC

trading dominates, there are other exchange platforms including the Intercontinental Exchange (ICE),

N2EX and APX as shown in Figure 7 (Ofgem, 2016). As previously mentioned, N2EX is an electricity

market platform of Great Britain operated by Nord Pool Spot AS. The first power exchange in the UK

was APX Power UK (prior name UKPX) founded in 2000. Since the integration of the businesses of the

APX Group and EPEX SPOT, APX Power UK spot market operates under the EPEX SPOT brand name

(APX, 2017). Finally, the ICE is an American financial company operating Internet-based marketplaces

which trade futures and OTC contracts as well as derivative financial products (Ofgem, 2016).


Version 1.2


Figure 7: Total monthly volumes of electricity traded in Great Britain across different trading platforms and churn ratio Source: (Ofgem, 2017)

The APX auction has a similar functioning as the one described for the case of EPEX SPOT in Germany

in section 3.1.3, with a few exceptions:

Auction times: 11:00 market closure, 11:42 preliminary results for information purposes only,

final results between 11:55 and 12:50 (UK Local Time)

Maximum volume for a block bid: 500 MW, maximum 80 block bid per trading account

More information on the EPEX SPOT UK auction can be found on (EPEX SPOT, 2017a) and in (Frontier

Economics, 2016).

Additional to the hourly auction, there is a half-hour day-ahead auction, which matches the half-hour

settlement periods used for balancing in the UK, managed by ELEXON. Some characteristics include:

15:30 market closure and results are returned by 15:45 (UK Local Time)

Double-sided blind auction (members cannot see the other bids/offers submitted)

Instruments are traded in GBP per MWh with two decimal precision

Traded in lots of 0.1 MW or a multiple thereof

Price must be between -500 £/MWh to 3.000 £/MWh


The market is closed to independent aggregators, to do so would require bilateral agreements with

each customer’s retailer. Demand response participation is in the form of flexibility of retailers and a

few very large industrial customers that are already trading members (Smart Energy Demand

Coalition - SEDC, 2017)

3.2 Balancing Power Reserve Markets


A general description into the approach of power balancing in the European electricity supply system

has been given in section 2.1. Previously mentioned in section 3.1.2, Balance Responsible Parties

(BRPs) are responsible for balancing their own portfolio of generators and/or loads and provide the


Version 1.2


TSO with binding schedules for every quarter-hour (or half-hour depending on the country) of the

next day. BRPs are then financially accountable for deviations from those schedules. The final

responsibility for the provision and management of balancing power is assigned to the TSOs in the

different countries which are often strictly regulated by national regulation authorities.

There are two geographic entities which are involved in this balancing: The synchronous system

(Continental Europe, UK, Ireland, Nordic or Baltic) and the balancing areas or control areas within this

synchronous system (generally delimited by country borders). The synchronous system is balanced

when system frequency equals 50 Hz and the balancing area is balanced if the net import balance is

at a scheduled value, meaning that the Area Control Error is zero (Hirth & Ziegenhagen, 2015).

There are a number of different power balancing products differing in the time frame of providing

the balancing service. Such services often imply two different types, which in some countries are

separated into different market products:

a. The allocation of power reserves that could be flexibly activated or deactivated depending on

the power balance in the grid. These reserves handle deviations from forecasted power in

control areas.

b. The act of providing or consuming (unscheduled) energy volumes. These reserves step in for

deviations in scheduled energy volumes for certain balancing groups.

Concerning business models it is possible to gain profits from either of the two service types,

depending on the individual specific needs. In any case, it is necessary to withhold certain power

reserves often leading to opportunity costs.

The balancing concepts here described are based on the current “Continental Europe Operation

Handbook” (entsoe, 2015) and are intended to provide a general understanding of the common

sequence and purposes of sequentially activated reserves. Nevertheless, it is important to notice that

the previously mentioned document is being replaced by the newly developed “System Operation

Guideline” (entsoe, 2016e) in the coming years. In every country the products associated with these

balancing concepts vary and can be related to more than one concept as it will be shown further on.

Synthetic Inertia

The kinetic energy stored in the rotating masses of synchronous generators absorbs the energy

imbalance and therefore the change in frequency immediately after a disturbance in what is known

as inertial response. The available system inertia determines the amplitude of frequency deviations

in case of load imbalances in the system. Total system inertia decreases as a result of the increasing

shares of generation connected to the grid through power electronics (such as wind and PV) and the

growth of power electronic drives being used at the demand side. In response to this recent

development ENTSO-E has published an Implementation Guidance Document (IGD) concerning the

provision of Synthetic Inertia (entsoe, 2017a).

The Network Code Requirements for Generators (RfG) defines Synthetic Inertia as “the facility

provided by a power park module or HVDC system to replace the effect of inertia of a synchronous

power generating module to a prescribed level of performance” (entsoe, 2017a). Sufficient levels of

system inertia are relevant for small synchronous areas with high penetration of non-synchronous

generation since they tend to have lower total system inertia; such is the case of Ireland and Great

Britain. Large synchronous areas, on the other hand, need sufficient levels of system inertia in order

to prevent system collapse in case of a system split and subsequent island operation. Requirements


Version 1.2


for synthetic inertia could apply for type C generators1 and above, HVDC systems and some demand

units.

There are 2 aspects of frequency stability where synthetic inertia is useful after a major disturbance,

the rate of change of frequency (RoCoF) and the maximum frequency deviation (see Figure 8):

1. Limiting the system initial rate of change of frequency (RoCoF): RoCoF must be kept below

the maximum capability of system users to remain connected. Future system design may

need to establish the lowest allowable system inertia per unit at synchronous area level

under the most challenging conditions. Each TSO/control block should consider its capability

to provide the necessary inertia in case of system split for its individual stability in addition to

contribution to overall synchronous area inertia.

Wind speed, solar radiation, demand size and available inertia should be taken into account

to determine the scale of synthetic inertia needed. Both generation and HVDC links could

provide synthetic inertia and the TSO should make sure that all units can survive the initial

RoCoF before activation of synthetic inertia in the system (100-500 ms).

The case of Ireland, where a “RoCoF remuneration mechanism” has been put in place, can be

used to exemplify market alternatives (EirGrid, 2017).

2. Limiting the maximum frequency deviation to avoid demand or generation disconnection:

Since reaching the nadir may take several seconds, fast frequency response can be used as

an alternative or supplement to address this aspect. Units like batteries, ultra-capacitors and

even demand response could provide very fast system frequency control.

Figure 8: Concept of RoCoF and maximum frequency deviation. Source: (entsoe, 2017a)

Synthetic inertia is an application, if given an economic value, which can add to the business case of

fast-responding and storage-capacity-limited units such as Battery Storage Energy Systems (BESS),

Hybrid Storage Energy Systems (HESS) and ultracapacitors. Not only is synthetic inertia being

considered as a separate product as shown for the case in Ireland, but also its value is being

considered for the development of new frequency response products, such as the case of Great

Britain (further described in section 3.2.6).

1 Power-generating module with connection point below 110 kV and maximum capacity at 50 MW (entsoe, 2016a).


Version 1.2


Primary control

Within a few seconds after inertial response acted on the RoCoF, primary control is automatically

activated in order to stabilize system frequency, preventing it to deviate any further. Full power

activation times are usually under 30 seconds and remain active for up to 30 minutes after the

disturbance. The service is provided either on both directions or is divided into positive and negative

products, depending on the regulatory framework.

The fast frequency response products found for the selected countries are categorized in this work

under the primary control tag. Within these services, is where the technical capabilities of fast-

responding units with a limited storage capacity are better exploited and where the business case is

usually better justified (see Figure 9 for the example in Germany). As such, simulations for the

provision of products falling under the primary control tag were performed for all countries

considered in this document. These products are described on the corresponding section for each

country and simulation results can be consulted in Annex 2 and Annex 3.

Secondary Control

Secondary control is intended to balance generation and consumption within a control area or block

as well as the system frequency within the synchronous area, thus gradually replacing primary

control. It is automatically activated making use of an Automatic Generation Control (AGC). The

requirement for the activation of these products varies within a time-frame of seconds up to 15

minutes after an incident.

Different from primary control, secondary control is commonly split up in products corresponding to

both directions, meaning the provision of positive control power (increased generation/discharging)

or negative control power (decreased generation/charging). The required volume of secondary

control depends on the size of the control area and the availability of power plants there. It should

be capable of compensating failure of the largest power plant in the control area.

Products being activated after the ones categorized under primary control reserve are considered as

secondary control. However, this classification is not yet harmonized among the countries selected

with reference to the new EU Network Codes (e.g. System Operation Guideline, Electricity Balancing

Guideline). Energy-limited resources can generally still find sufficient remuneration within this

category but given the common technical requirements a business case might be more suitable for

aggregated and/or multiuse energy-limited units (see Figure 9).

Tertiary control

Tertiary control power is activated manually in case of sustained activation of secondary control. Its

purpose is to replace or supplement secondary reserves after large incidents to restore system

frequency. This last kind of control is generally not attractive for energy-limited resources due to the

technical requirements and low remuneration (see Figure 9). It may be however of interest for other

technologies considered in the project such as CHPs.


Version 1.2


Figure 9: Average power price for control reserve products traded in the regelleistung.net platform (Fraunhofer ISE, 2017)

3.2.2 EU Regulation and Rules for Procurement

The European Network of Transmission System Operators for Electricity ENTSO-E started to develop

a “Network Code on Electricity Balancing” based on framework guidelines on electricity balancing

published by the “Agency for the Cooperation of Energy Regulators” (ACER). Details are given in

(entsoe, 2017). The desire is to increase harmonisation of the rules for balancing and for using

ancillary services in order to extend effective pan-European competition to these markets and

increase efficiency. The latest version of the Balancing Guideline, which was approved by the

member states in March 2017, is published on (entsoe, 2017).

The “Guideline on Electricity Balancing” will foster and accelerate the process of an EU

harmonisation of balancing products, balancing markets and rules for all participating actors. The key

player for defining the technical specifications and procedures are the TSO having the obligation to

set up products for replacement reserves, frequency restoration reserves with manual activation and

frequency restoration reserves with automatic activation.

Additionally, the LFC in the EU (described in section 2.1) is currently regulated by the ENTSO-E

“Operation Handbook” (entsoe, 2015). However, this document is soon to be replaced by the

“System Operation Guideline” (entsoe, 2016e), which is yet to pass validation from the European

Parliament and Council to enter implementation stage.

The following terminology is used in the “Network Code on Electricity Balancing” and the upcoming

“System Operation Guideline”, which describes the LFC process in the EU (Figure 10):

Frequency Containment Reserve (FCR): active power reserves available to restore or support

the required level of FRR to be prepared for additional system imbalances.

Frequency Restoration Reserve (FRR): reserves available to restore system frequency to the

nominal frequency and restore power balance to the scheduled value (for synchronous areas

with more than one LFC area). The terms “automatic” and “manual” refer to whether

balancing energy is triggered manually by an operator or automatically in a closed-loop

manner. This should not be mistaken with the approach regarding the communication

procedure between TSO and plant operator which today is mostly being organised as

automated data exchange procedures.

o Automatic Frequency Restoration Reserves (FRR-A)


Version 1.2


o Manual Frequency Restoration Reserves (FRR-M)

Replacement Reserve (RR): reserves available to restore or support the required level of FRR

to be prepared for additional system imbalances, including operating reserves.

Figure 10: Sequence of LFC processes. Source: (entsoe, 2013)

The countries selected for analysis in this report are located in different synchronized systems. The

characteristics of each synchronized system such as the level of interconnection, the generation mix,

and the total system capacity are all influencing factors in the system frequency. The regulatory

framework for frequency control services is naturally developed to fit these system characteristics.

Therefore, there are differing balancing concepts with various products among the investigated

countries.

The relation between the EU nomenclature and product characteristics and those found for products

in each country is not always explicitly addressed in consulted documentation. Nevertheless, to

provide an overview of the products investigated, a summary of the nomenclature is presented in

Table 3. In this table, the products and grouped according to their characteristics such as activation

time. The difference lies on the fact that Tertiary Control is divided as follows (entsoe, 2013):

FRR-M: directly activated tertiary control which can be activated independent from a time-

frame of exchange schedules and is part of the frequency restoration process.

RR: scheduled activated tertiary control, which is activated in relation to predefined time-

frame of schedules, which is part of the reserve replacement process.


Version 1.2


Table 3: Summary for nomenclature for frequency control reserves in the selected countries

Primary Control Secondary Control Tertiary Control

EU Frequency

Containment Reserve

Frequency Restoration Reserve Restoration Reserve Automatic Manual

Germany Primary Control

Reserve Secondary Control

Reserve Minute Reserve N/A

Spain Primary Regulation Secondary Regulation Tertiary Regulation Deviation

Management

Sweden

FCR-Disturbance

FRR-A

FRR-M: Fast active reserve

(forecast, disturbance and counter trading)

and Slow active reserve

N/A

FCR-Normal

Great Britain

Primary, secondary and high response

(Mandatory and Firm) N/A Fast Reserve

Short Term Operating

Reserve, Demand Turn Up and BM-

Startup Enhanced Frequency

Response

In light of these differences, there are several on-going projects focused on harmonization of the

load frequency control and balancing processes including:

FCR Cooperation: a common market for procurement and exchange of FCR where Austrian, Swiss,

Dutch, Belgian, French and German TSOs participate with Denmark foreseen as an upcoming

participant.

EXPLORE Cooperation: working on a consistent common FRR market design. Members include TSOs

of Austria, Belgium, Germany and the Netherlands.

Trans European Replacement Reserves Exchange (TERRE): aimed for cross-border Replacement

Reserve exchanges. The project involves TSO’s from Portugal, Spain, France, UK, Switzerland, Italy

and Greece as participants with TSO’s from Ireland and North Ireland as observers.

Manually Activated Reserves Initiative (MARI): focused on designing, implementing and operating a

platform for exchange of energy from Manual Frequency Restoration Reserves in 2017. Participating

TSO’s from:

Member: Finland, Sweden, Norway, Denmark, Germany, Great Britain, Netherlands,

Belgium, France, Czech Republic, Switzerland, Austria, Portugal, Spain, Italy and Greece.

Observers: Lithuania, Hungary and Slovenia.

In process of becoming observers: Latvia, Estonia, Romania and Croatia.

Since the time frame for implementing the Network Code on Electricity Balancing is up to 2 years

after entry into force, the national codes remain applicable for the near future. It can be expected

that national regulations significantly influence the definition of the new standard products for

balancing energy and balancing capacity. In the following sections, for the purpose of describing and

evaluating business options for storage systems the focus lies on current national regulation systems

for selected EU countries.

One of the current topics of discussion revolves around the “minimum activation period”, which is

defined as the period during which energy-limited resources should be able to provide maximum


Version 1.2


power. The final value will be set between 15 and 30 minutes based on cost-benefit analyses

performed by all TSOs from CE and Nordic synchronous areas, where the requirement is applicable

(entsoe, 2016e). For Great Britain, this time period is linked to the activation time of the next reserve

in linear the time specified by National Grid.

The final setting of the “minimum activation period” can drastically affect the potential of BESS as

FCR providers as shown by (Hollinger, Motte Cortes, Erge, & Engel, 2017). Among other effects, it

causes an increase in battery capacity needed per potentially offered power for FCR, which reduces

the potential profitability of providing the service.

3.2.3 National Regulation (Germany)

Responsibility of the provision of sufficient balancing power in Germany has been assigned to the 4

German TSO, namely Tennet TSO, 50Hertz Transmission, Amprion and TransnetBW. These TSO

procure balancing services via tenders published on the web page regelleistung.net. This site also

contains documents and links to information describing the technical and non-technical details for

bidding at the auctions and delivering the services. Tenders are regularly published for the following

products. In the present context of battery systems only the first three options are relevant and will

be discussed further on. A summary with relevant procurement parameters for these reserves is

presented in Table 4:

Primary control reserve

Secondary control reserve

Minute reserve

Immediately interruptible loads

Quickly interruptible loads

Table 4: Procurement parameters for German control reserve market

Primary Control Reserve Secondary Control Reserve Minute Reserve

Products Single product,

bidirectional

Base-negative Base-positive Peak-negative Peak-positive

Positive and negative products divided in 4 hour

slots

Minimum power

1 MW 5 MW 5 MW

Tender frequency

Weekly Weekly Daily

Remuneration Capacity price Energy and capacity price Energy and capacity price

Settlement rule Pay-as-bid Capacity: Pay-as-bid Energy: Pay-as-bid

Capacity: Pay-as-bid Energy: Pay-as-bid

Activation rule Merit order Merit order Merit order

Activation time <30 s 5 min 15 min

Minimum sustained delivery

15 min – 30 min >4 hrs Indefinitely

Time availability

100% 95% 100%

Tendered power in May

2016 793 MW

Neg.: 1 904 MW / Pos.: 1 973 MW

Neg.: 2 006 MW / Pos.: 2 779 MW

Sources: (entsoe WGAS, 2017), (entsoe, 2016e) , (Deutsche ÜNB, 2015a), (Hollinger R. , et al., 2016), (Verband der

Netzbetreiber VDN e.V. beim VDEW, 2003), regelleistung.net.


Version 1.2


Participation in the market for control reserve in Germany requires a prequalification process of the

technical units by the TSO responsible for the control area. One basic requirement for participating in

the markets for balancing reserves is the permanent reservation of balancing power and continuous

ability to deliver balancing energy throughout the full contracted period of time.

Legal basis for tendering of reserve power in Germany are the Energy Act “Energiewirtschaftsgesetz -

EnWG” (EnWG, 2017) and decisions by the German regulatory body (“Bundesnetzagentur”).

Especially the Bundesnetzagentur determines market rules and access conditions for each market

product.


An aggregator-BRP requires retailer-BRP’s agreement before offering consumption flexibility to the

market. An independent third-party aggregator would require negotiating contracts with the

consumer, the consumers’ BRP, the TSO and the DSO. A highlighted barrier is the difficulty to reach a

bilateral agreement on schedule exchange and compensation payments with the consumer’s BRP

and retailer, which are potential competitors and thus have no interest with the aggregator to reach

such an agreement (Smart Energy Demand Coalition - SEDC, 2017).

3.2.3.1 Primary Control Service

The TSO are responsible for the procurement of the required control power to restore the power

balance to the grid in their respective control zones. During the last years market cooperation was

set up between Germany, France, Netherlands, Switzerland, Austria and Belgium. This market

cooperation is being realised in a two stages process. At stage 1 national TSO tender the needed

power volumes nationally. After finalization of the tendering, offers of the cooperating countries are

combined in a central clearing system (CSS) and using a merit order procedure the most cost efficient

solution to cover the needed volume is determined. Just after that successful tenderers are being

informed.

Current tenders for primary control issued by the German TSO (see regellestung.net) add up to a

total of 1391 MW (period: 10.04.-16.04.17) integrating required control reserve for the countries

Germany, France, Netherlands, Switzerland, Austria and Belgium. The average capacity price for this

period was 2,140 Euro/MW, the marginal capacity price 2,311 Euro/MW. The overall primary control

reserve in the Continental Europe (CE) synchronous area is agreed to be 3,000 MW. Automatic and

complete activation of the primary control reserve must be realised within 30 seconds. Primary

control reserve is meant to cover incidents with time periods 0 < t < 15 min.

Technical units providing primary control services need to be assigned to balancing groups and the

service provider needs to have a valid Energy Identification Code (EIC). Pooling of a number of

technical units in one control area is possible; operators may run multiple pools in parallel. One

aspect that might become important for energy storage system is the option to combine technical

units providing positive primary control power with other units providing negative control power.

The assignment of single technical units to the specific pool is flexible (can be changed at the

beginning of each quarter of an hour). The operator of the pool might be asked to inform the TSO

about the technical units forming the pool for the upcoming day.

Technical requirements for Primary Control Reserve (PCR):

Automatically operating decentralised frequency controllers (error in frequency

measurement less +/- 10 mHz)

Setpoint for frequency: 50 Hz


Version 1.2


Automatic activation by a given power-frequency characteristic (P-f characteristic)

throughout the entire period of one week

Tolerated frequency deviation band between 49.99 Hz and 50.01 Hz (dead band +/- 10 mHz)

Linear increase of PCR power for deviations between 10 mHz and 200 mHz up to 100% of

the bid amount, 100% PCR power for deviations higher than 200 mHz for both positive and

negative control powers

100% availability, provision of maximum PCR power per incident for up to 15 minutes

Must not be impaired by parallel provision of other reserve power products (e.g. secondary

control

Monitoring and documentation of power curves for the technical units, online access for the

TSO to those data (partly aggregation of single units possible)

Accuracy of monitoring: 2 seconds / 2% error, storage of monitoring data for at least 2

weeks

Establishment of permanently (24/7) reachable contact point for operational procedures

Neither overfulfillment nor underfulfillment is allowed for conventional providers.

Overfulfillment has been defined as PCR power provision 20 % above the targeted set point,

at least 5 MW (this aspect might become relevant in the context of recharging battery

systems)

Details regarding IT requirements for PCR providers can be found at (regelleistung.net,

2017a).

The provision of PCR by a unit with limited storage capacity is illustrated in Figure 11. The unit

responds to a deviation from the nominal frequency of 50 Hz. The battery charges when the

frequency is higher than the nominal value and discharges when the frequency is lower. Within the

deadband frequency range, no PCR response is required.

Figure 11: Frequency response capability applicable to the German PCR product (Fraunhofer ISE, 2017)

Trading of Primary Control Reserve (PCR):

Online trading platform „regelleistung.net“

Publication of tenders: Weekly, Tuesday 3 p.m.

Bidding closes on Tuesday the week before delivery


Version 1.2


Period covered by a single tender: 1 week

Only power price bid, supplied energy is not paid for

Minimum offer: 1 MW, increment: 1 MW steps

Merit order system for covering the estimated PCR demand

Remuneration: pay-as-bid (capacity price)

Additional documentation addressing storage capacity requirements was developed by German TSOs

(Deutsche ÜNB, 2015a). It is required that batteries reserve enough capacity to be able to provide full

PCR power in any direction during a minimum uninterrupted period (either 30 minutes or 15

minutes, depending on the case). In Figure 12, the case shown is for a battery which is only used to

increase flexibility in a pool of units without a limited storage capacity, without increasing the offered

PCR power. The reserved capacity is shown in white in terms of the battery’s State of Charge (SoC)

and with a higher storage capacity to PCR power ratio the reserved capacity decreases.

Only under three cases is the SoC allowed to cross the aforementioned limits:

1. Frequency deviation outside ±200 mHz

2. Frequency deviation outside ±100 mHz lasting more than 5 minutes

3. Frequency deviation outside ±50 mHz lasting more than 15 minutes

Under these cases, the battery is said to be operating in “abnormal mode”. Conversely, when SoC is

within these limits, it is said to be operating in “normal mode”.

Figure 12: Battery SoC limits for the provision of PCR during at least 15 minutes for a changing ratio of capacity-power. Based on: (Deutsche ÜNB, 2015a)

Additionally, a set of Degrees of Freedom (DEGOF) are described for providers of PCR by the German

TSOs (Deutsche ÜNB, 2015b). These DEGOF, which are further described by (Hollinger R. ,

Diazgranados, Wittwer, & Engel, 2016) and (Zeh, Müller, Naumann, Hesse, & Witzmann, 2016) are

applicable for any participant trading in the regelleistung.net platform and include:

Deadband: The small range around the nominal value where provision of FCR is not required.

Overfulfillment: A provision of up to 120% of the instantaneous power requirement is

allowed so the system operator gets extra power for the same tendered price.

Time correction process: Adjustment of synchronous time to astronomical time.


Version 1.2


Gradient: Depending on the full activation time and full activation frequency deviation. This

can be used to the battery’s advantage since it has an instant ramping unlike conventional

units.

Delay: Regulation recognizes a delay in initial activation of frequency response. This delay

originates from the time frame between detection of the frequency deviation, instruction of

response and final change in output for provision.

The delay DEGOF is an artificial delay explicitly prohibited in the upcoming System Operational

Guideline. Nonetheless, although very small, a delay is always present between detecting the signal

and providing a change in output. According to the “Network code on requirements for grid

connection of generators” of the European Commission, “the relevant TSO may specify a shorter

time than two seconds (entsoe, 2016a)” for power-generating modules without inertia.

As this is currently the case for most regulatory frameworks, DEGOF can be implicitly found in the

technical requirements from the perspective of batteries. Therefore, these DEGOF can be utilized in

favour of the providing unit, thereby improving SoC management and ultimately decreasing

operation costs.

3.2.3.2 Secondary Control Service

The four German TSOs established a single control power market for secondary control reserve (SCR)

in 2009 being combined with cost-effective secondary control reserve retrieval across the control

areas. Differing from PCR, SCR is being activated in those control areas where system imbalances

occur. Thus no cross-border transmission capacities have to be reserved for the provision of SCR. The

volume of SCR power being activated by the TSO depends both on current frequency deviations from

its set point and deviations of the cross-control area power flows from previously agreed schedules.

Current tender volumes for secondary control are 1846 MW negative control reserve (“NEG”) and

1913 MW positive control reserve (“POS”) (period: 10.04.-16.04.17). There are two tendering

products: “base (NT)” and “peak (HT)” product. The average capacity and marginal capacity price for

this period was:

NEG_HT: 0.32 EUR/MW (average) 5.75 EUR/MW (marginal)

NEG_NT: 115.32 EUR/MW (average) 225.00 EUR/MW (marginal)

POS_HT: 144.45 EUR/MW (average) 190.00 EUR/MW (marginal)

POS_NT: 190.21 EUR/MW (average) 322.00 EUR/MW (marginal)

Pooling of a number of technical units in one control area is possible. In order to meet minimum bid

limits of the tendering process it is possible to combine technical units in different control areas. One

operator can run several pools in parallel. In the case of retrieval of SCR, the TSO communicates only

set values for the whole pool while the pool operator is free to select technical units for provision of

the service (can be adjusted flexibly). A different approach with direct control of technical units by

the TSO can be agreed as well. Details regarding the control of SCR pools are given in the document

(Forum Netztechnik/Netzbetrieb im VDE (FNN), 2009).

TSO might ask to be informed day-ahead until 5 p.m. which technical units are scheduled for

operation on the next day. The TSO may define a certain ramp for the power change at the beginning

and at the end of SCR provision.

Changes in the Secondary Control Reserve market were introduced on June 13 and will come into

force in July 2018. An analysis of these changes performed by (Mayr & Adam, 2017) highlights the

following:


Version 1.2


Auction frequency increase from weekly to daily auctions.

Product time slices shortened to six blocks with duration of four hours each. This is valid for

both positive and negative products

Bids <5MW are permitted (in 1 MW steps) if the bidder submits only one bid per SCR

product, time slice and control area.

Asset collateralization (necessary to secure provision of reserve in case of failure of a

technical unit) will be possible with prequalified assets from other control areas.

Publishing of four-second interval data on SCR target values sent from the TSOs.

Technical requirements for Secondary Control Reserve (SCR):

100 % availability.

Provision of SCR power according to set point (minimum deviations are acceptable).

Full SCR power must be reached within 5 minutes after retrieval.

During pre-qualification certain characteristic for power changes are defined that need to be

followed in operation.

Feed-in needs to be realised at agreed grid connection points and online monitoring data of

current power must be provided for the TSO.

Activation lead time: 5 minutes.

The TSO might request further monitoring data (gradients, operating points, etc.) for a time

period of 15 min before SCR provision to 15 min after SCR provision. Operation protocols

must be stored for at least 6 weeks.

The secondary control energy is being calculated on a 15 min basis.

Establishment of permanently (24/7) reachable contact point for operational procedures.

Overfulfillment has been defined as SCR power provision 10% above the targeted set point

(at least 5 MW).

Details regarding IT requirements for SCR providers can be found at (regelleistung.net,

2017a).

Trading of Secondary Control Reserve (SCR):


Publication of tenders: Weekly, Wednesday 3 p.m.

Bidding closes on Wednesday the week before delivery

Period covered by a single tender: 1 week

Separate tendering of positive and negative SCR

Two products: peak (Mo-Fr 8a.m. to 8 p.m.) and base

Offers need to include capacity price and energy price

Allocation by capacity price merit-order

Minimum offer: 5 MW, increment: 1 MW steps (positive and negative)

Retrieval of energy by energy price merit order system

Remuneration: pay-as-bid (capacity price and energy price)

3.2.3.3 Tertiary Control Service

Technical units providing SCR need to fulfil rather high technical requirements, especially regarding

the activation time. In cases of longer lasting system imbalances it is reasonable to replace such units

by the so called tertiary control units with less flexibility. Tertiary control in Germany is called


Version 1.2


“Minutenreserve” (minute reserve); following the terminology used above it will be abbreviated

“TCR” in the next paragraphs. TCR must be deployed in time to contribute to restoring balance no

more than 15 minutes after the start of the deviation in the control area and should be active (if

needed) until 1 hour after occurrence of the imbalance. Power imbalances lasting longer that one

hour should be handled by the balancing groups being responsible for the energy imbalance.

Tendering is being done by the German TSO for the whole German supply area (tendering of a

minimum capacity for single control areas is allowed). Since 2010 also the retrieval of TCR energy is

coordinated between all control areas thus optimising cost aspects. In contract to SCR and PCR the

TCR is activated “manually” meaning that TSOs select on a case-by-case basis required capacities,

even for preventive purposes in some cases.

Normally technical units offering TCR services need to be connected to the German grid. The

required volume of tertiary control depends on the size of the control area and the availability of

power plants there. German TSOs use a probabilistic dimensioning method to procure sufficient

control reserves.

For TCR 6 products (á 4 hours) are tendered daily. Current tender volumes for TCR are: 1072 MW

negative control reserve (“NEG”) and 1506 MW positive control reserve (“POS”) (period: 10.04.17).

The average capacity and marginal capacity price for this period was:

Negative TCR, all products: 0.00 EUR/MW (average) 0.00 EUR/MW (marginal)

Positive TCR, across timeslots: 0.17 EUR/MW (average) 0.90 EUR/MW (marginal)

Variation of average capacity price for positive TCR was between 0.00 and 0.42 EUR/MW depending

on the time slice.

Pooling of a number of technical units in one control area is possible. In order to meet minimum bid

limits of the tendering process it is possible to combine technical units in different control areas. One

operator can run several pools in parallel. For retrieval the TSO issue only one aggregated request for

TCR provision which has to be split up to single technical units by the operator of the TCR pool

himself. TSO might ask to be informed day-ahead until 5 p.m. which technical units are scheduled for

operation during the next day.

From the technical point of view TCR is rather attractive for smaller operators and controllable

consumers because of the short tendering period and the six time slices. Yet, from the economic

perspective, TCR is the least attractive option compared to PCR and SCR.

Technical requirements for Minutenreserve / Tertiary Control Reserve (TCR):

100% availability

Provision of full TCR power within 7.5 to 22.5 min after activation (lead time to 1/4h - raster

is varying)

Monitoring equipment proving TCR provision must be installed by the operator, operation

protocol with 1 min – resolution required

Operation protocols must be stored for at least 6 weeks

Overfulfillment has been defined as TCR energy provision 20% above the schedule per 1/4h

interval

Establishment of permanently (24/7) reachable contact point for operational procedures

Details regarding IT requirements for TCR providers can be found at (regelleistung.net,

2017a). The basic protocol is ssh-ftp and the TCR provider has to operate a ssh-ftp-server.


Version 1.2


Conventional phone services are the fall-back solution in cases of failing electronic data

transfer.

Trading of Minutenreserve / Tertiary Control Reserve (TCR):


Daily (Mo-Fr) with 6 x 4-hour blocks (0-4 / 4-8 / 8-12 / 12-16 / 16-20 / 20-24)

Friday auctions for Sa/So/Mo

Separate tendering of positive and negative TCR

Minimum offer: 5 MW, increment: 1 MW steps (positive and negative)

Publication of tenders: daily (day ahead), bidding closes at 10 a.m.

Offers need to include capacity price and energy price

Allocation by capacity price merit-order

Retrieval of energy by energy price merit order system

Remuneration: pay-as-bid (capacity price and energy price)

3.2.3.4 Imbalance Settlement

Settlement takes place no later than the 42th working day after the delivery month. reBAP is a

symmetric imbalance price per MWh which is used as the single uniform price to settle BRP

imbalances in Germany. It is calculated based on the control energy costs arising in a quarter hour

period, divided by the deployed amount of control energy (secondary and minute reserves) in the

same period. reBAP can be either positive or negative depending on the purchase of either positive

(charging) or negative (discharging) balancing energy depending on the sign of the total control

energy used in that period (Consentec GmbH, 2014). Table 5 shows the direction of payments

according to the sign of reBAP. More information of how the price is determined can be found in

(regelleistung.net, 2017b).

Table 5: Pricing model for imbalances in Germany

Positive reBAP Negative reBAP

Causes positive imbalance of BRP

Generation surplus BRP ← TSO BRP → TSO

Under consumption

Causes negative imbalance of BRP

Generation shortage BRP → TSO BRP ← TSO

Over consumption

According to an investigation by (Smart Energy Demand Coalition - SEDC, 2017), an aggregator must

pay the BRP/retailer for the energy curtailed due to providing demand response, on the basis of their

commercial agreement. The retailer/BRP set the prices since there is no standard or regulatory

framework on such agreements. As of April 2017, a framework proposal for demand response

developed by industry stakeholders includes:

Standardisation of consumer’s BRP agreement and energy compensation

Standards for information and schedule exchange

Framework which allows for compensation from the aggregator to the BRP for administrative

efforts during an interim period (to be changed at the latest by 2020).


Version 1.2


3.2.4 National Regulation (Spain)

The national electricity grid in Spain is operated by “Red Eléctrica de España”, which is a partly state-

owned and public limited. Only secondary and tertiary regulation services are traded in the Spanish

markets for ancillary services, while primary regulation is a non-remunerated mandatory service.

Relevant parameters for the provision of control reserves in Spain are summarized in Table 6. There

are two services available additional to the control reserves:

Deviation management market: this service solves expected deviations which could appear

in the period between intraday market sessions. It enables the System Operator (SO) to

resolve imbalances without putting the availability of secondary and tertiary reserves at

stake. If deviations above 300 MWh between intraday market sessions are identified or

predicted ahead of each hour, the SO may initiate a deviation management market session.

Additional upward power reserve market: aims to contract additional reserve to what was

originally scheduled.

Table 6 Procurement parameters for Spanish control reserve market

Primary Regulation Secondary Regulation Tertiary Regulation

Products Single bidirectional Positive and negative Positive and negative

Minimum power

1.5% of nominal capacity 10 MW 10 MW

Tender frequency

N/A Daily (hour blocks) Daily (hour blocks)

Remuneration None Energy and capacity price Energy price

Settlement rule N/A Capacity: Pay-as-bid

Energy: Marginal pricing Marginal pricing

Activation rule Pro rata (parallel

activation) Merit order

Merit order (based on capacity)

Full activation time

<30 s Delay: <30 s

Full activation: <100s <15 min


15 min 15 min >2 hours

Time availability

100 % 100 % 100 %

Tendered power (2015)

316 MW Upwards: 692 MW

Downwards: 536 MW Upwards: 849 MW

Downwards: 717 MW Sources: (entsoe WGAS, 2017), (entsoe WGAS, 2017), (Red Eléctrica de España, 1998), (Red Eléctrica de España, 2006).

Yearly average values for secondary and tertiary regulation obtained from the TSO’s information platform ESIOS (Red

Eléctrica de España, 2017).

Up to now, there are no reported cases of providers with a limited storage capacity participating in

the control reserve in Spain. With the project “Almacena”, the system operator has investigated

between 2013 and 2015 the potential use of BESS to “(...) improve the efficiency of system operation

(Red Eléctrica de España, 2013)”. Thought to be the first project in the country, two battery packs

were connected to a 3 MW wind turbine to “(...) improve the quality of the energy sent to the grid

and provide advanced technology services (Colthorpe, 2017)”.


Currently, demand-response providers neither have access to the balancing market, nor to ancillary

services (Smart Energy Demand Coalition - SEDC, 2017).


Version 1.2



Primary regulation is a mandatory and non-remunerated service for all generators. However,

generators can install storage systems to adjust their capacity for primary regulation (stoRE Project)

Due to its compulsory nature, if a generator is not able to provide the service it must be contracted

from another agent who is able to provide it. More information can be found in the Operating

Procedure 7.1 (Red Eléctrica de España, 1998).

Before the 31st of December, the SO communicates the requirements for Primary Regulation

calculated as Spain’s share of the primary control reserve necessary for Continental Europe (Red


Technical requirements for Primary Regulation:

100% availability

Minimum capacity: 1.5% of nominal power

Activation delay shorter than 15 seconds if imbalance is < 1500 MW

If imbalance is larger than 1500 MW 50% of reserve must be active before 15 s from the

moment of the incident and linearly achieve 100% within 30 s

Minimum sustained provision time: 15 minutes until secondary control takes over

Insensibility of measurement: < ±10mHz

The frequency response capability for Primary Regulation is the same as the one shown for PCR in

Figure 11. A mandatory scheme is not expected to be able to achieve a cost-efficient allocation of the

service as much as a competitive market such as the regelleistung.net market would. However, given

the lack of a market for this service, the Primary Regulation potential profit calculation available in

Annex 2 was performed by using prices for the regelleistung.net market. Since technical regulatory

requirements are very similar to those found in Germany (both part of the Continental European

synchronized grid) results are quite similar.


Secondary regulation is an optional ancillary service managed by competitive mechanisms. It is

defined as the power variation margin which the unit can automatically provide in both directions at

any working capacity it is currently operating. In Spain, the term regulation band (esp. “banda de

regulación”) is commonly utilized to refer to the power margin reserved in each direction.

Secondary regulation is provided by Control Zones in response to the master regulator’s

requirements, known as the Peninsular Shared Regulation (RCP). This master regulator distributes

regulation requirements in real time among the different Control Zones based on the market share

obtained the previous day in the secondary reserve market.

In order to participate in the control reserve, a unit must be registered in the register for electricity

generators RAIPEE (esp. “Registro Administrativo de Instalaciones de Producción de Energía

Eléctrica”). The service is compensated based on availability and energy used. Energy volume used to

provide the service is valued at the marginal price of the avoided tertiary regulation energy need,

either upwards or downwards. The energy volume is calculated as the energy imbalance with respect

to schedule caused by a unit following the AGC signal. A positive imbalance is known as upwards

secondary regulation energy (esp. “energía de regulación secundaria a subir”) and a negative

imbalance is known as downwards secondary regulation energy(esp. “energía de regulación

secundaria a bajar”) (Red Eléctrica de España, 2015a).


Version 1.2


The tendered upwards secondary reserve is calculated by taking into account the forecasted demand

level in the control area (i.e. the Spanish peninsular system) as recommended by the Union for the

Coordination of Transmission of Electricity (UCTE) regulation. Downwards secondary reserve power is

established between 40 % and 100 % of the upwards secondary reserve power. However, in off-peak

hours a minimum of 500 MW of upwards regulation and 400 MW of downwards regulation must be

ensured. More information on reserve level calculation is given in Operating Procedure 1.5 (Red


The requirement for secondary regulation is daily set by the system operator for every hourly period

of the next day’s schedule. The requirements are published before 16:00 and the bidding process

normally closes before 17:30 with winning bids being assigned before 17:45 (Red Eléctrica de España,

2015a). Information for the pre-qualification test can be found in Section I. page 1199282 of the

Operating Procedure 7.2 (Red Eléctrica de España, 2015a). Aggregation is possible for units of the

same scheduling unit and control centre. Tests for service provision are possible even if aggregate

capacity is <10 MW; however, participation is only allowed for a minimum capacity of 5 MW.

Maximum aggregated capacity cannot exceed 900 MW.

Technical requirements for secondary regulation:

Activation delay: < 60 s

Full activation: within < 100 s

Minimum sustained provision time: 15 minutes until replaced by tertiary regulation

Signal is updated every 4 seconds

Trading of secondary regulation:

Remuneration: merit-order (capacity price and energy price)

Publication of tenders: Daily previous to operation day D (i.e. D-1)

Upwards and downwards tendering.

Only capacity price required

Minimum offer: 10 MW


Tertiary regulation is an optional, remunerated ancillary service; however, it is an obligatory service

for those units which are capable to provide it. All such units must offer their exceeding capacity (not

contracted in other markets or services) to the system operator. The requirement for tertiary

regulation, as the tertiary control service is called in Spain, is daily set by the system operator for

every hourly period of the next day’s schedule. The requirements are published every day before

21:00. All bids must then be presented before 23:00 previous to the operation day (Red Eléctrica de

España, 2015a). No indivisible bids are accepted and must be continuously updated when schedule

modifications or unit availability changes. The market mechanism is based on a minimum-cost

criterion and the settlement mechanism uses marginal-pricing and differentiates between upwards

and downwards activated tertiary reserves (Red Eléctrica de España, 2015c). Unlike secondary

reserve, payments are only given by the TSO if the service is required.

Upwards secondary reserve must be equal to the maximum generation loss caused by the failure of a

generator, incremented by 2% of the forecasted demand in every scheduling period. Downwards

secondary reserve is established between 40 % and 100 % of the upwards secondary reserve (Red

Eléctrica de España, 2006). Information on the pre-qualification test can be found in page 119935 of

2 These Operating Procedures are published in Spain’s Official State Gazette (esp. Boletín Oficial del Estado).


Version 1.2


the corresponding regulation (Red Eléctrica de España, 2015a). Aggregation is allowed for units of the

same scheduling unit and control centre. Tests are allowed even if aggregated units sum up to less

than 10 MW; however participation in the service is not allowed until aggregated units reach at least

10 MW. The maximum aggregated capacity cannot exceed more than 1000 MW.

Technical requirements for tertiary regulation:

Minimum capacity required: 10 MW

Full activation time: < 15 min.

Minimum sustained provision time: ≥ 2 hours.

Trading of tertiary regulation:

Upwards and downwards tendering.

Remuneration: merit-order (only energy price required)

Publication of tenders: Daily previous to operation day D (i.e. D-1).

Only capacity offers are taken to assign regulation


Regulation on a balancing mechanism (esp. mecanismo de gestión de desvíos) can be found in

Operating Procedure 3.3 (Red Eléctrica de España, 2015b). Imbalances are managed between

Scheduling Units (esp. unidades de programación), which are comprised by one or several generating

units (specifics can be found on ANNEX II of the previously mentioned Operating Procedure).

In this market, offers against the expected imbalance are taken. In other words, when a negative

(positive) imbalance is expected, up-regulating (down-regulating) offers are taken. Any deviation

appearing 15 minutes before operation is managed by the TSO. The cost of managing these

deviations is then incurred by the BRPs according to Table 7.

Table 7 Prices applicable to BRP under the imbalance pricing model in Spain

Up-regulating hours Down-regulating hours

Positive imbalance of BRP

Generation surplus Sell at intraday market price Sell at positive imbalance price

Under consumption

Negative imbalance of BRP

Generation shortage Buy at negative imbalance price Buy at intraday market price

Over consumption

When imbalances are in favour of the system, the BRP does not incur any penalization and settles the

deviation at the intraday market price. When imbalances are against the system, two different prices

may apply:

Positive imbalance price: Calculated as the minimum between the intraday market3 price

and the weighted average price of energy from down-regulating deviation management4,

tertiary regulation and secondary regulation. BRP is penalized by receiving a lower price for

the energy used than the intraday price.

3 esp. Mercado diario 4 esp. Precio de las energías a subir de gestión de desvíos


Version 1.2


Negative imbalance price: Calculated as the maximum between the intraday market price

and the weighted average price of energy from down-regulating deviation management,

tertiary regulation and secondary regulation. BRP penalized by paying a higher price for the

energy used than the intraday price.

3.2.5 National Regulation (Sweden)

Sweden is part of the interconnected Nordic synchronous system, which also includes the

subsystems of Norway, Finland and Eastern Denmark. Western Denmark is connected to the

Synchronous System through DC interconnectors. Each TSO in the Nordic synchronous system is

responsible to ensure availability of system services within their own subsystems. Considering

balance regulation, the Nordic system is divided into two balancing areas: the Nordic Synchronous

Area and Western Denmark. Regulation is apportioned according to frequency response requirement

and a merit-order regulation list (entsoe, 2006).

Comparing it to EU regulation, there is no product which accounts for Replacement Reserves. While

FRR-M and FRR-A are procured via the Nord Pool platform, FCR services are procured within national

markets. Svenska Kraftnät, Sweden’s TSO, is then responsible for managing procurement of FCR in

Sweden. Starting 2017, settlement and billing services will be provided by eSett Ltd., a company co-

owned by Svenska Kraftnät with the TSOs from Finland (Fingrid) and Norway (Statnett).

The “active reserve” is divided into “automatic active reserve” and “manual active reserve” (entsoe,

2016c). The “automatic active reserve” is equivalent to FCR and divided in:

Frequency controlled normal operation reserve (FCR-N)

Frequency controlled disturbance operation reserve (FCR-D)

Voltage controlled disturbance reserve

The “manual active reserve” is the active reserve, which is activated manually during the momentary operational situation. This is equivalent to FFR and is divided into:

Fast active forecast reserve: FRR-M for regulation of forecasting errors for consumption and production.

Fast active disturbance reserve: FRR-M available within 15 minutes in the event of the loss of an individual principal component (production unit, line, transformer, bus bar etc.). Restores the frequency controlled disturbance reserve.

Fast active counter trading reserve: FRR-M for counter trading.

Slow active disturbance reserve: FRR-M available after 15 minutes. There is no equivalent to the replacement reserve available in the Nordics (entsoe, 2016b). Figure 13

shows the sequence of activation of the previously described reserves. FCR-N responds to small

deviations and while FCR-D responds to larger frequency deviation, the objective of both being

stabilizing the frequency. Afterwards, FRR gradually replaces these reserves and restores the

frequency to its nominal value.


Version 1.2


Figure 13: Frequency containment and frequency restoration processes in Sweden (entsoe, 2017b)

A summary of procurement parameters for the previously mentioned reserves is shown in

Table 8. In this document, FCR-N and FCR-D are considered under Primary Control Service (section

3.2.5.1), FRR-A and FRR-M are described under Secondary Control Service (section 3.2.5.2) and since

there is no equivalent for replacement reserves, the corresponding section is ignored.

Table 8: Procurement parameters for selected services in the Swedish control reserve market

FCR-N FCR-D FRR-A and FRR-M

Products Single product,

bidirectional

Present: Single unidirectional (upregulating)

Upcoming: single bidirectional

Single product, bidirectional

Minimum power

0.3 MW 0.3 MW

FRR-A: Between 1MW and 5 MW

FRR-M: Between 5 MW and 10 MW

Tender frequency

Daily (hour blocks) Daily (hour blocks) Daily (hour blocks)

Settlement rule Capacity: Pay-as-bid

Energy: Marginal pricing Capacity: Pay-as-bid

Energy: Marginal pricing Capacity: Pay-as-bid

Energy: Marginal pricing

Remuneration Energy and capacity price Energy and capacity price Energy and capacity price

Activation rule Pro Rata (Parallel

Activation) Pro Rata (Parallel Activation) Merit order


63% in 1 min, 100% in 3 min

50% in 5 s, 100% in 30 s

FRR-A: < 120 s FRR-M: < 15 min


15 min 15 min 1 hour

Time availability

100 % 100 % 100 %

Tendered power (2015)

225 MWd 412 MWc Fast Active Disturbance

Reserve: 1290 MW Sources: (Svenska Kraftnät, 2015b), (Svenska Kraftnät, 2016a), (entsoe, 2016b), (entsoe, 2016c), (Frontier Economics, 2016). cExample for week 15/2013 (entsoe, 2016c). d Calculated according to (entsoe, 2016e), with data from (entsoe, 2017)

Like in most of the Nordic countries, Sweden relies heavily on hydropower for power generation, and

thus control reserves (Lundqvist, 2014). This provides the Nordic synchronized system with sufficient

flexibility in the short-term. Yet, providers with a limited storage capacity are included in the

solutions being considered in the long term to improve frequency quality and address decline in

system inertia (Svenska Kraftnät, Stattnet, Fingrid, Energie.dk, 2016b).


Version 1.2



Although demand-side resources are legally allowed to participate in an aggregated manner in all

reserves, technical requirements may prove inadequate for some potential providers (Smart Energy

Demand Coalition - SEDC, 2017).

Future developments

Currently a new concept for balancing is being developed in the Nordics. The main publication

describing the new concept is “The Nordic Balancing Concept” (Svenska Kraftnät, Statnett, 2017). The

main features of this all-new concept include:

Synchronous area defined as an LFC block, divided into bidding zones (same as currently

existing market areas) which correspond to an LFC area.

Quarter-hour balancing market and imbalance settlement.

FRR dimensioning based on historical imbalances and dimensioning incident in each bidding

zone.

A new methodology to exchange balancing capacity to ensure sufficient balancing reserves

and economic efficiency.

Exchange of balancing capacity based on reservation of transmission capacity.

FRR-M used to proactively balance the system and for congestion management purposes.

“Proactively” refers to forecasted imbalances and the release of expected automatic FRR-A

activation.

FRR-M control requests from each bidding zone will be coordinated by a Continental

European or Nordic activation optimization function.

FRR-A is activated based on a control proper to each bidding zone, coordinated by a central

activation optimization function.

Establishment of a joint balancing market with joint platforms for procurement and

activation of balancing services. Scarcity pricing is to be applied.

Redesign of the Frequency Containment Process, adoption is aimed at the long term given

the broad impact on generation.


Both FCR-N and FCR-D are considered part of the automatic active reserve, along with the voltage

controlled disturbance reserve.

FCR-N is used to balance the system within the standard frequency deviation range (±100 mHz).

Consequently, its full activation frequency deviation is also defined as ±100 mHz. According to the EU

System Operation Guideline (see section 2.1), the applicable deadband for the Nordic system is

±10 mHz. The frequency regulation capability required for FCR-N providers is shown in Figure 14.

The requirement for FCR-N is divided between the subsystems within the synchronous system based

on the previous year’s annual consumption (total consumption excluding power plant own

consumption), as described in the upcoming System Operation Guideline (entsoe, 2016e). While FCR-

N can be traded between subsystems, at least 2/3 of the FCR requirement is to be maintained within

each subsystem. This is due to transmission constraints and in case of a potential split-up and island

operation of a subsystem.


Version 1.2


Figure 14: FCR-N regulation capability for continuously controlled providers

FCR-D is used to control large disturbances. When the frequency drops below 49.90 Hz, the product

is activated and then linearly increases until fully activated at 49.5 Hz. FCR-D is currently a

unidirectional service; however, a rework of the technical requirements for both products is

underway. In the latest available draft of the new requirements (ENTSO-E, 2017e), FCR-D is split in

asymmetrical products: FCR-D upwards and FCR-D downwards. The upward capacity is activated at

49.90 Hz and increases linearly until fully activated at 49.5Hz, while the downward capacity is

activated at 50.10 Hz and increases linearly until fully activated at 50.5 Hz. Automatic load shedding

can be counted as frequency controlled disturbance reserve. The frequency regulation capability for

providers under this new concept is shown in Figure 15.

The required total power of FCR-D is distributed between the subsystems (bidding zones) according

to N-1 criteria and is updated at least once a week. The service is mainly provided by hydropower

with some HVDC interventions and automatic start-up of gas turbines.

Figure 15: FCR-D regulation capability for continuously controlled providers

Providers are compensated for both capacity offered and actual energy generated to the system.

Balance providers are able to make bids for one day (D-1) and two days (D-2) after the operating day.


Version 1.2


Both single hourly bids and blocks of hourly bids are possible on both modalities but bids for

simultaneous provision of FCR-N and FCR-D are not allowed.

Exchanges in Elspot, as well as joint Nordic balance regulation have priority over the exchange of the

automatic active reserve, therefore exchange of FCR-N and FCR-D is agreed only after Elspot closure.

A Balance Responsibility Agreement example with technical requirements and trading information

for FCR reserves is available in (Svenska Kraftnät, 2015a).

Technical requirements for frequency containment reserves:

The BRP shall report to Svenska Kraftnät’s at least every third minute: measured values for

available power FCR-N and FCR-D and current regulation capability situation.

FCR-N:

Full activation: 63 % in 1 minute, 100 % in 3 minutes

Full activation frequency deviation: ±100 mHz

Minimum sustained provision time: 15 minutes

FCR-D:

Full activation: 50% in 5 seconds, 100% in 30 seconds

Full activation frequency deviation: ±500 mHz

Activated at a deviation of ±100 mHz


Trading of frequency containment reserves:

The joint requirement for the synchronous system is 600 MW (i.e. 6000 MW/Hz)

Joint requirement for the interconnected Nordic power system is approximately 1200 MW,

depending on the relevant dimensioning fault.

Can be offered to the system operator during D-2 and D-1 trading.

Bids are divided into FCR-N and FCR-D respectively and are possible to submit a bid for only

one of the two reserves.

Selected bids cannot be retracted by the supplier, but repurchases can be made D-1 after

contacting the system operator.

D-1 Trade is thought for supplemental procurement on the evening before operating day and

even on delivery day on exceptional cases.

Capacity settlement follows pay-as-bid methodology.

Energy settlement is done at a different price depending if the net sum of FCR provision

results in an up-regulating imbalance or a down-regulating imbalance in a given hour.

o For up-regulation, the payment is based on the price difference between the up-

regulation imbalance price and the day-ahead price.

o For down-regulation, the payment is based on the down-regulation price and the

costs caused by the difference between the measured energy and the latest

submitted production plan

D-2 Trade:

Maximum possible bid: 6 hours.

Submission via electronic communications everyday (Ediel Quotes format) before 15:00 hrs.

Selected bids are notified by 16:00 hrs on the same day bidding takes place.


Version 1.2


Plans for FCR-N or FCR-D divided by market area must be received by the system operator no

later than 16:00 hrs the day before operation day.

D-1 Trade:

Maximum possible bid: 3 hours.

Submission via electronic communications everyday (Ediel Quotes format) before 18:00 hrs.

Selected bids are notified by 20:00 hrs on the same day bidding takes place.

Bids can be modified up to 2 hours’ prior notice.

Plans for FCR-N or FCR-D divided by market area must be received by the system operator no

later than 23:00 hrs the day before operation day.

The provision of FCR-N was found to put significant stress on a battery (Annex 3), depending on how

much of the total battery power is dedicated for this service. A large number of cycles along with

extreme and rapid changes in SoC caused by the technical requirements of this product would result

in severe battery degradation. Moreover, unavailability could also become an issue. According to

Annex 1, the prices paid for FCR-N by Svenska Kraftnät for the year 2015 do not compensate for the

degradation suffered by the battery. This suggests that BESS should only partially provide this service

or do so when pooled with a generating unit. This goes in line with one of the first approaches to

integrate units with a limited storage capacity into the control reserves in the Nordic synchronized

system, which has been implemented as support for hydropower to prevent premature wear and

tear of turbines (International Water Power and Dam Construction). There are also reports of a pilot

project planned to start in December 2016 where water heaters were to be aggregated as a product

for FCR-N (NordREG, 2016).

On the other hand, the FCR-D product results in low stress levels for the battery (Annex 3) and,

although prices paid are lower than those for FCR-N, potential profit is higher as seen in Annex 1.

Moreover, due to its low utilization, this is a product which could be easily stacked with other

applications described in this document.


The Secondary Control Service is comprised by the Manual Frequency Restoration Reserve (FRR-M)

and Automatic Frequency Restoration Reserve (FRR-A).

FRR-A was introduced in January 2013 as one of the main measures to take care of a decreasing frequency quality. It is an automatic complement to FRR-M in the FRR process which is based on a merit order and that takes congestions in the grid into account. Also, it has a faster response than FRR-M and is remotely controlled by a centralised controller. It can be exchanged across synchronous systems, whereby a reserved capacity in the grid could be necessary (entsoe, 2016b). Currently FRR-A is procured nationally in a non-harmonised market design (Statnett, Fingrid, Energinet.dk, Svenska Kraftnät, 2016a) and a clear difference with FCR has not been made: “Up until December 2015 an agreed volume of FRR-A for specific hours was procured in the synchronous system with the same distribution key as FCR. From January 2016 the procurement has been put on hold because Svenska Kraftnät (Editor's note: System Operator of Sweden) decided not to procure FRR-A in 2016 until a permanent Nordic solution was agreed between the Nordic TSOs (entsoe, 2016b)”. FRR-M objective is to bring frequency back to the frequency target and replace both FCR and FRR-A in the process. It is also used to handle congestions in normal and disturbance situations. Given numerous congestions and a limited FRR-A volume, the Nordic system depends strongly on FRR-M as its main balancing resource (entsoe, 2016b).


Version 1.2


There are currently only national requirements for sufficient upward regulation FRR-M to handle the largest dimensioning fault in each subsystem. Each area separated by congestions must have sufficient volumes of FRR-M or other reserves to handle imbalances in both directions including BRP imbalances, potential outages/disturbances of production, consumption or grid elements. There are different capacity arrangements for FRR-M in the Nordic countries. Both voluntary bids and resources that TSOs pay capacity payment for are submitted to the RPM for activation. The reserves with capacity payment are for securing capacity for disturbances, congestions or imbalances. Peak load reserves may also be available for FRR-M. The different resources are gathered in a Nordic merit of order list for activation. FRR-M can be used for other than the needs of balance management. For this purpose, TSO uses bids which are suitable in terms of congestion management or other specific reasons, and the bids are not necessarily used in the price order. Technical requirements for FRR:

The BRP shall report to Svenska Kraftnät’s operating information system at least every 36th

second: real time measured values for production (active and reactive power by facility).

FRR-M:

Real time measurement obligatory for Regulation Objects with an activation time < 15

minutes. The required activation time in the RPM (15 min) is a Nordic compromise between

need for frequency and congestion control, and the need for liquidity in the market (entsoe,

2016b).

Measuring inaccuracies may not be greater than 5%.

No real time measurement required for Regulation Objects with an activation time longer

than 15 minutes.

In case of proactive activations, the FRR-M may be activated in the opposite direction of FCR and FRR-A.

FRR-A:

Full activation time: 120 seconds.

Automatic via control signal from TSO.

Trading of FRR:

The market players can submit bids to the Nordic Regulation Power Market (RPM). The RPM

is a tool for the TSOs to perform market-based balancing with bids activated in price order

when needed.

FRR-M:

Bids submitted via electronic communications (Ediel Quotes format).

Minimum offer in bidding areas 1, 2 and 3: 10 MW.

Minimum offer in bidding area 4: 5 MW.

Bids with information concerning regulation power in MW

Price per MWh. Highest permitted price for upwards regulation is 5000 €/MWh.

Upwards regulation bids submitted with a plus sign and downwards regulation bids

submitted with a minus sign.

Activation times must always be stated.

It is possible to submit, amend or remove bids from 14 days prior to the delivery day.


Version 1.2


Bids can be change up until 15 minutes before delivery hour after which they become

economically binding.

The TSO can request the provider to adjust planned time for start or stop of Regulation

Objects up to 15 minutes earlier or later than the operation hour. The provider may refuse if:

1) it is technically not possible to fulfil the request, 2) incurs significant cost increases or 3) is

forbidden by law. This change may be compensated by the most advantageous choice for the

provider out of two options: Upwards or downwards regulation price in the respective

market area or the stop price in the respective market area ± 10%.

Both voluntary bids and resources that TSOs pay capacity payment for are submitted to the RPM for activation.

The reserves with capacity payment are for securing capacity for disturbances, congestions or imbalances.

Peak load reserves may also be available for FRR-M.

FRR-A:

Bids submitted via electronic communications (Ediel Quotes format) before tan 10.00 hrs. for

the upcoming period Saturday-Friday

Hourly bids priced per MW

Separate up- and down regulation bids

Bid volume in steps of 5 MW and activation also in steps of 5 MW

Automatic activation via control signal from TSO

Maximum bid of 3 hours

Selected bids are notified by 11:00 hrs. on the same day as bidding takes places

Plans for selected FRR-A to be received by TSO before 16:00 hrs. the day before delivery

Plans are to be updated if changes occur

Capacity settlement follows pay-as-bid methodology

Energy settlement for up regulation (down regulation) is priced at the most advantageous up

regulation price (down regulation price) in the respective market area.


The Nordic system is divided into two balance areas, the synchronous system itself and Western

Denmark. Each TSO is responsible to balance its own control area. The volumes needed for regional

balancing are agreed between TSO and each region.

The BRPs balance their portfolio on an hourly base. This is achieved through day-ahead trade in Nord

Pool, intraday market and bilateral trade. Gate closure for sending final settlement information to

the respective TSO is 45 minutes before the operational hour. Afterwards, balancing is ensured by

the TSO. System imbalances happen due to different reasons, including events causing loss of

consumption or generation or differences between forecasted schedules and actual generation or

consumption. A quarterly hour production plan applies during a certain period of time for Swedish

BRPs when the hourly production plan changes more than 200 MW at hour shift.

The imbalance settlement is performed by eSett. The imbalance price (see Table 9) follows a two-

price model for production imbalances and a one-price model for consumption imbalances.

Automatic reserves, such as FCR and FRR-A are not taken into account in the imbalance price. Either

the up or down regulation price from the regulation power market or the Elspot price from Nord Pool

is applied to the imbalance. The imbalance price at which eSett sells electricity to settle the deficits of


Version 1.2


a BRP is always equal to or higher than the price with which eSett buys the surpluses of a BRP (eSett,

2017).

Table 9: Pricing model for imbalances in eSett


Causes positive imbalance

Generation surplus Elspot market price Down regulation price

Under consumption Down regulation price

Causes negative imbalance

Generation shortage Up regulation price

Elspot market price

Over consumption Up regulation price

3.2.6 National Regulation (UK)

There are four high voltage transmission networks in the UK: National Grid (England and Wales), SP

Energy Networks (South Scotland), Scottish and Southern Electricity Networks (North Scotland) and

Northern Ireland Electricity Networks. In Great Britain, where this document is focused, the

responsible for system balancing services is National Grid. The terminology and functioning of the

products and services available to balance the system in Great Britain differ in many aspects to those

described in EU regulation and are divided in:

Frequency response: services used to maintain frequency within ±1% of nominal system

frequency (50.00Hz) save in abnormal or exceptional circumstances, as required by the

“Electric Safety, Quality and Continuity Regulations” (Parliament of Great Britain, 2002).

o Mandatory Frequency Response (MFR)

o Firm Frequency Response (FFR)

o Enhanced Frequency Response (EFR)

o Frequency Control by Demand Management (FCDM)

Reserve services: these reserves are described as extra power needed to manage unforeseen

imbalances in the system and are required in longer timescales than frequency response.

They include: Fast Reserve, Short Term Operating Reserve (STOR), BM Start-up, STOR

Runaway, Enhanced Optional STOR and Demand Turn Up.

National Grid uses the Balancing Mechanism5 (BM) to accept offers and bids to balance the system.

To participate in the BM, a unit or a set of units must be registered as a Balancing Mechanism Unit.

The latter is defined as a “collection of plant and/or apparatus, considered the smallest grouping that

can be independently controlled. As a result, most BM Units contain either a generating unit or a

collection of consumption meters (ELEXON, 2017).”

In Great Britain, Elexon is defined as administrator of the Balancing and Settlement Code. Elexon is in

charge of managing the metered electricity volumes delivered and consumed, revise the energy

imbalances generated, set the imbalance price and procure settlement of these imbalances between

the participating parties. More information on these and other services, including reactive

5 After suffering some delays, the Balancing Mechanism is to be replaced in 2018 by the Electricity Balancing System (EBS). More information can be found on (National Grid, 2017e).


Version 1.2


power/voltage control and black start, can be found in the “System Needs and Product Strategy”

(National Grid, 2017l).

Table 10: Procurement parameters for selected services in the control reserve market in Great Britain.

Mandatory and Firm Frequency Response

Enhanced Frequency Response

Fast Reserve

Products Primary and Secondary:

upregulating High: downregulating

Single bidirectional Single bidirectional

Minimum power

1 MW 1 MW 50 MW

Tender frequency

Monthly Unknown

(Last tender in Jul 2016) Monthly

Settlement rule Pay-as-bid Pay-as-bid Pay-as-bid

Remuneration Energy and capacity price Energy and capacity price Energy and capacity price

Activation rule Pro rata (parallel activation) Pro rata (parallel activation) Merit order


Primary: 10 seconds Secondary: 30 seconds

High: 10 seconds <1 second < 2 minutes


Primary: 30 seconds Secondary: 30 minutes

High: Indefinite 15 minutes 15 minutes

Time availability

>90 % response for 95% of the time

>90 % response for 95% of the time

>90 % response for the whole response period

Power requirement

MFR Average Volume Held: Primary: 258 MW

Secondary: 163 MW High: 427 MW

FFR Dynamic Requirement:

Primary: 500 MW (day), 700 MW (night)

Secondary: 500 MW (day), 600 MW (night) High: 400 MW

200 MW (Tender Jul 2016)

Monthly updated Optimal requirement:

300-600 MW Tendered: 0-400 MW

Sources: (entsoe, 2016b), (entsoe, 2016c), (National Grid, 2017a), (Underhill, Matthew, Cheung, & Sims, 2016), (National

Grid, 2016a), (National Grid, 2017h), (National Grid, 2017f).

A summary of the most relevant products within the response and reserve services is shown in

Table 10. Within this report, response services are categorized under primary control service, while

reserve services are categorized under tertiary control service. According to (Lian, Sims, Yu, Wang, &

Dunn, 2017), the concept of secondary control service (i.e. FRR) doesn’t actually exist in Great

Britain. This might refer more precisely to FRR-A rather than FRR-M, which is categorized under

tertiary control service in this report. Under the products available for the reserve service, Fast

Reserve is the most adequate for batteries; however batteries could find opportunities within other

products together with other technologies.


Almost all balancing services are open to demand response and aggregated loads but the product

design is not adequate for many potential participants. The aggregator does not require a BRP’s

agreement prior to load management and have direct access to consumers, which means that the


Version 1.2


retailer/BRP and not the aggregator is the one exposed to imbalance payments (Smart Energy

Demand Coalition - SEDC, 2017).

Future developments

In recognition of the need of a more flexible system, particularly close to real-time and in response to

limitations from the actual balancing services such has inaccessibility to al providers and over-

complicated products; National Grid is planning to make radical changes to its balancing services. The

key future needs include:

Inertia and RoCoF: instead of looking into a specific inertia market, National Grid is exploring

the possibility to take the value of inertia into account in a new frequency response product

or in the future voltage market. Additionally, commercial arrangements for synchronous

compensators are being explored (This is part of the Scottish Power led project “Project

Phoenix”).

Frequency Response: considering changes to response products to provide a market route

for faster-acting response. This is also expected to reduce overall volume of response

needed. These actions are to be implemented by March 2018.

Reserve: considering new reserve products in order to increase flexibility close to real time

and to be compatible to European reserve services. Actions to be completed by 2018/2019.


Mandatory Frequency Response (MFR): As a condition of connection to the transmission system, all

large generators (Table 11) must prove capability to provide mandatory frequency response.

Although mandatory, the service is remunerated based on capability to provide response when

instructed and for the amount of energy utilized from or discharged to the system. It is used to

maintain system frequency within Great Britain’s statutory limits (±500 mHz) and the standard

frequency range (±200 mHz) (National Grid, 2013b).

Table 11: Generator size considerations from different TSOs in the UK

National Grid Scottish Power Scottish Hydro Electricity Transmission

Small <50MW <30MW <10MW

Medium 0.50MW=<100MW N/A N/A

Large =>100MW =>30MW =>10MW

Firm Frequency Response (FFR): In order to complement the other frequency response services, firm

frequency response was created as a market route for potential providers with different

characteristics and whose services would otherwise not be accessible. Both mandatory and firm

frequency response services consist on the same products (Figure 16): Primary, secondary and high

response. These asymmetrical products were designed to make it possible for a single unit to provide

them simultaneously. Primary and secondary are down-regulating products while high up-regulating.

Additionally, there is the possibility of providing a rapid response for primary and high services. This

rapid response refers to a reduction in the full activation period from 10 seconds to 5 seconds

(National Grid, 2017g).


Version 1.2


Figure 16: Time scales for frequency response products within mandatory and firm frequency response

In terms of EU regulation, FCR would relate to a combination of all three response products.

Although a concept of FRR doesn’t actually exist (Lian, Sims, Yu, Wang, & Dunn, 2017) the rest of

balancing services available are adequate for returning frequency to its nominal value and restoring

the activated reserves. Figure 17 shows the response capability required for providers of dynamic

FFR. A dynamic service cannot provide primary response only and thus requires both primary and

secondary response. The ability of the provider to remain within the allowable tolerances given is

tested for all response types (i.e. primary, secondary and high). Recently updated testing

requirements for pre-qualification can be found in the Firm Frequency Response section in National

Grid’s webpage (National Grid, 2017m).

Figure 17 Frequency response capability and allowed power tolerance for FFR. Source: (National Grid, 2017n).

Technical requirements for Firm Frequency Response:

An FFR a providing unit may not supply any other service which may undermine the provision

of FFR without previous notice to National Grid.

Applicable deadband for Great Britain: ±15 mHz

Full activation time: Primary (10 s), Secondary (30 s) and High (10 s)

Minimum sustained provision time: Primary (30 s), Secondary (30 min) and High (indefinite).

Declaration of expected frequency response capability in MW at different frequency

deviations in the capability data tables.


Version 1.2


It is not possible to provide only Primary response, other combinations allowed include:

Primary and Secondary, Primary, Secondary and High and High only.

Providers will not be allowed to manage their state of charge within the deadband

Asymmetrical provision is possible

Trading of Firm Frequency Response:

Qualified participants can then submit tenders for single or multiple time periods but only

one tender per unit is finally accepted.

Tenders may have overlapping service terms in respect of the same providing unit given that

the service terms are mutually exclusive.

The minimum offered power for FFR has been recently lowered from 10 MW to 1 MW under

certain conditions

Provision is payed based on availability and nomination prices, which together make up for

the tender price.

o Availability is defined by the aggregated number of hours a resource is available

within contracted time periods.

o Nomination refers for a payment when the unit is actually assigned to provide FFR.

Historically, it has always been paid for all tendered hours.

o Other payments apply under special circumstances and are further described in the

“Firm Frequency Response tender rules and standard contract terms” (National Grid,

2017g).

The energy-based payment, referred to as response energy payment, equals to zero when a

Balancing Mechanism Unit is associated or registered in respect of a power station not

incurring any fuel costs (e.g. wind, solar, tidal and wave energy). More information can be

found in the Further applicability and calculation of this payment can be found in National

Grid’s FFR webpage and in the “Connection and Use of System Code – Section 4” (National

Grid, 2017c).

Availability and amount of provision are monitored by National Grid at random sample

periods of 30 minutes starting from any frequency excursion from the nominal value.

Performance measure is then used to calculate deductions in payments to the provider

during the period it was contracted and expected to provide FFR.

Provision may not be lower than 90 % of expected amount for at least 95% of the time.

If the provider is unavailable or fails to respond the due payment is set to zero.

Additional to deductions in payments failure to respond may lead to contract termination.

Non-capability is determined based on records kept by the provider.

Subject to certain conditions, if the provider is deemed as unavailable or fails to respond for

more than three times in a calendar month, the contract is terminated.

Enhanced Frequency Response (EFR): National Grid recently developed the EFR product to address

the reducing system inertia caused by increasing shares of renewable generation. The first tender for

EFR took place on July 2016, where an aggregated 201 MW were awarded four-year contracts. This is

a product developed with storage resources in mind and thus introduced a new degree of freedom

(DEGOF) which supports SoC management. This DEGOF is shown in Figure 18 and is referred to as

Envelopes within which the provider is allowed to locate the frequency response output to a

frequency deviation, given certain ramping limitations shown in Figure 19.


Version 1.2


Technical requirements of Enhanced Frequency Response:

May not be provided simultaneously with another commercial service.

Two deadbands with different widths that define two separate products:

o EFR Narrow: ±15 mHz.

o EFR Wide: ±50 mHz.

The wider deadband was implemented to allow for more providers to take part on the EFR

service.

Full activation frequency deviation for both products is set at ±500 mHz.

Figure 18: Frequency response capability for the EFR products. Source: (National Grid, 2016b).

Maximum ramp rates are put in place to ensure that output changes in a proportional way to

frequency while still providing flexibility to the provider.

This requires continuous measuring of df⁄dt which given inherent inaccuracies will delay the

response to a very fast frequency deviation; however, it reduces the chances of delivery

overshoot and unpredictable behaviour.

Figure 19: Allowed ramp rates per second for EFR as a percentage of operational capacity


Version 1.2


Ramp rates within the envelope (marked as B) depend on the rate of change of frequency

and are calculated as shown in Figure 20.

The service envelope always takes precedence over the ramp rate limits. Therefore, ramp

rate limits will be overridden where the output of the EFR assets is near the edge of the

envelope.

Figure 20: Ramp rates per second allowed in area B of Figure 19.

Trading of Enhanced Frequency Response:

May not be provided simultaneously with another commercial service.

Energy usage outside the deadband is excluded from the imbalance calculation for the

provider and not charged for6. Nonetheless, providers are “(…) responsible for any costs

whilst inside the deadband for SoC management or ancillary services (National Grid, 2016b)”.

Only an availability payment is due for every settlement period7.

A performance measure is utilized to calculate a payment reduction for each calendar month

of service provided. Further details are found in the “Invitation to tender for pre-qualified

parties” for EFR (National Grid, 2016b).

Frequency Control by Demand Management (FCDM): provision of down regulating frequency

response through interruption of demand customers. Demand is automatically interrupted when

measured frequency crosses an on-site low frequency relay (National Grid, 2017i).

Technical requirements for FCDM:

Activation delay < 2 seconds


Minimum power accepted: 3 MW (aggregation is allowed)

Provision of output signal into National Grid’s monitoring equipment.

Trading of FCDM:

Provision through bilateral negotiations with providers.

Provider must install a Tripping Relay Equipment and Communication Router

National Grid provides FCDM computer equipment, test and commissions.

Provider must declare availability for each settlement period on a weekly bases, National

Grid decides whether to accept it or not.

6 Energy is classified as Applicable Balancing Services Volume Data (ABSVD), which refers to energy

associated with the provision of applicable balancing services (ELEXON, 2017b). 7 Details for payment structure available in Appendix 7 of the tender documentation (National Grid, 2016b).


Version 1.2



Fast Reserve: It is defined as an increase in output generation or reduction in consumption following

a dispatch instruction from National Grid. Provision may be as a firm service, which is subject to a

tender process or an optional service, which is sometimes requested from National Grid to

unsuccessful bids in the monthly tender. It is used to control frequency changes arising from sudden

and unpredictable changes in the generation-demand balance. It may be used to assist the recovery

of system frequency by replacing and restoring primary and secondary response capability. The

service is open to both BM and non-BM participants. It can be provided by generators connected to

the transmission and distribution networks, storage providers and aggregated demand side

response. Although there is a monthly-set optimal requirement that oscillates between 300 and 600

MW, Fast Reserve has an undersubscribed market: the tendered quantities are normally under or on

the lower end of the requirement and even without any contracted fast reserve for some months.

This issue is considered in National Grids vision for future Balancing Services (National Grid, 2017l).

Technical requirements Fast Reserve:

Activation delay < 2 minutes

Minimum power: 50 MW

Activation at rates ≥ 25 MW/min


Delivery from a pre-instructed loading level to instructed loading to the time instructed by

National Grid with a tolerance of ±30 s

If provision falls below 90% of contracted amount in any minute, provision is considered to

have failed.

Trading of Fast Reserve:

Monthly tender

Three possible bids: Single month (1 calendar month), multiple month (2-23 calendar

months) and long term (2-10 years) submitted no later than the 1st business day of the

month.

A “month ahead fast reserve requirement” is published by National Grid.

Providers may submit more than one bid for the same unit as long as the provision periods

overlap. On the contrary, only one bid is accepted if they are mutually exclusive.

Bids may be retrieved at any time prior to receiving written notification from National Grid

confirming acceptance.

The payment structure includes the following payments:

o Firm Availability Payment: calculated based on the Availability Fee and aggregate

number of hours of tendered service periods.

o Optional Availability Payment: calculated based on the Optional Availability fee and

the period of time the service was available until: 1) National Grid notified the

provider that the service is no longer required 2) The provider notified National Grid

it is unable to provide the service.

o Enhances Rates Availability Fee: payed for the optional service providers with

enhanced MW activation rates.

o Positional Payment: it may be requested as part of the Fast Reserve tender that the

unit maintains dynamic parameters in a certain position to provide Firm Fast

Reserve.


Version 1.2


o Window Initiation Fee: National Grid notifies the provider of windows (i.e. periods)

within the tendered availability period where the service is required.

o Utilization Payments: related to the energy used in provision.

Short Term Operating Reserve (STOR): The requirement for this reserve is a function of the system

demand profile, and thus varies depending on the time of the year, week and day. Provision is

classified into six seasons on the year which include working days (Monday to Saturday) and non-

working days. Total requirement is around a minimum 1 800 MW and 2 300 MW. The service is open

for BM and non-BM providers, where the latter have an option to provide a “flexible service” or a

“premium service” where the provider chooses the availability windows which it makes the service

available once the tender is accepted. National Grid assesses whether to accept or reject this

availability. Further information can be found in the “General Service Description on STOR” (National

Grid, 2017j).

Technical requirements STOR:

Bidirectional

Activation delay < 240 minutes after request from National Grid

Minimum power: 3 MW. Aggregation is permitted.

Minimum sustained provision time: 2 hours

Recovery period after provision: < 20 hours

Must be able to deliver at least 3 times per week

Not possible to provide other services simultaneous to providing STOR.

Trading of STOR:

Three tender rounds per year.

Maximum availability of 3800 hours per year.

Due payments for providing the service include:

o Availability payments: for making a unit available within an availability window. It is

payed on a £/MW/h basis.

o Utilisation payments: Payment for the energy delivered on a £/MWh.

o Optional Utilisation payments: the single payment given to non-BM providers. Non-

BM providers are allowed to offer the service outside the availability windows.

Demand Turn Up: This service seeks providers to either increase demand (through shifting) or reduce

generation when there is excess energy on the system, typically overnight and weekend afternoons.

The service can be provided in a fixed or flexible modality. The fixed modality has guaranteed

availability payments where providers declare themselves available (National Grid, 2017d).

Technical requirements for Demand Turn Up:

Minimum entry threshold: 1 MW (This can be aggregated from sites 0.1 MW and larger).

Not possible to provide other services alongside demand turn up.

Minimum minute by minute or half-hourly metering on-site.

There is no general minimum sustained provision time, this will be asked by National Grid

taking into account the provider’s capabilities and instructions will not exceed agreed limits.

However the average sustained provision time for 2016 was 4 hours 20 minutes.


Version 1.2


There is no general activation delay, this will be asked by National Grid taking into account

the provider’s capabilities and instructions will not exceed agreed limits. However the

average sustained provision time for 2016 was 7 hours 20 minutes.

Trading of Demand Turn Up:

Payments due include an availability payment and an utilisation payment based on energy

delivered.

Starting from 2017, the providers are allowed to submit their own prices for the services.


Forward bilateral contracts and power exchange markets operate until market closes at so-called

“Gate Closure”; after this point, the System Operator takes over as the residual balancer. To

participate in this Balancing Mechanism, imbalance information is submitted and continually updated

to the System Operator until Gate Closure, which occurs one hour before real time settlement

period. In this way, along with other measures, the System Operator is able to know the actions

necessary to balance the system.

The sum of the difference between contracted positions and physically traded electricity indicates

the imbalance of the system. A participant with a long position has contributed to the surplus in the

system; these participants are charged the System Sell Price (SSP). On the other hand, participants

with a short position have contributed to a deficit in the system and are therefore charged at System

Buy Price (SBP). The calculation of these prices varies according on the direction of market imbalance

in each particular settlement period as noted in Table 12 (ELEXON, 2016).

Table 12: Imbalance settlement pricing model in Great Britain


Causes positive imbalance

Generation surplus Power Market Index (System Sell Price)

Down regulation price (System Sell Price) Under consumption

Causes negative imbalance

Generation shortage Up regulation price (System Buy Price)

Power Market Index (System Buy Price) Over consumption

3.3 Peak Shaving and Local Grid Services


Services described in 3.2 (power balancing) are of non-locational nature, meaning that the

identification of the need for the service and the mechanism of service provision are not bound to

specific geographic locations but are implemented within the whole system of transmission and

distribution grids of regions, countries or even (in the case of primary control) in the whole UCTE

network. This is reasonable because power imbalances jeopardize the stability of the whole EU

network and can be mended by measures at distant locations.

Peak shaving and grid services addressed in this section are localized services addressing primarily

distinct grid connection points, single distribution grids or regional grid operation. The aspect of a

influencing the maxima of net grid load on a national or EU level will be left out in the current

context.


Version 1.2


Peak Shaving

The meaning of “peak shaving” in the given context is to limit the maximum value (either positive or

negative) of the power flow between some consumer/generator and the public grid. Reasons for

peak shaving might be restrictions from the grid operator or special requirements of the feed-in

tariff. The most “unintelligent” solution of peak shaving of RES generation (like PV) is to just curtail

the output power and “throw away” excess energy. Yet there are reasonable alternatives.

Normally the relevant power flow is determined by the meters at the grid connection point

separating the public electricity grid and the local house installation. Because of the aggregation of all

technical units located in the local grid (before the grid connection meter) peak shaving can be

achieved by coordinated energy management of generation, controllable loads and available storage

systems. If the technical units are connected to the public grid via separate meters this aggregation

normally is not possible even if the units are situated at the same location.

When talking about peak shaving different applications and strategies have to be distinguished. In

general there are two different types of scenarios where peak shaving will be relevant:

Type 1: Peak shaving for a (long-term) limiting of the maximum power at the grid connection

point of some house / installation / system8

Type 2: Peak shaving which directly or indirectly serves the alleviation of (momentary)

maximum power peaks in grid segments, in the whole electricity grid, or which should avoid

short-term imbalances between generation and load in the national electricity system.

The difference between these two types is mainly the focus being either at the local grid

interconnection point or a contribution to the stabilization of the whole electricity grid. Type 1 peak

shaving affects the individual services from the grid operator for the house owner thus directly

touching the grid use tariff or costs related to local grid enforcement. Precondition for this is an

existing capacity component in the tariffs or charges depending on the maximum peak power. Table

13 shows a summary of the key elements in network tariffs for households and small industries. As

can be seen there, often energy charges (kWh) dominate the electricity tariff and the capacity

component (kW) is less relevant (meaning relatively weak incentives for the limitation of peak

power).

Table 13: Key elements of European distribution households and small industries network tariffs (EURELECTRIC, 2016), (European Commission Directorate B, 2015)

8 In the following text „house“ will be used as synonym for all facilities having an individual and metered grid connection point and local electricity consumption / generation / distribution behind this connection point.


Version 1.2


Type 2 peak shaving is some sort of service for the public grid and being remunerated in different

ways. One example for that are special feed-in remuneration schemes that require a shaving of feed-

back peaks as an alternative to other (more expensive) technical measures9.

From the general perspective consequent and intelligent peak shaving could level out grid load thus

helping to delay or avoid grid extension or grid enforcement measures for the distribution or even

transmission grids. Currently there is no systematic business model existing linking local peak shaving

flexibilities to financial revenues accruing from avoided grid enforcement.

Note that “peak shaving” might be a business option on its own (as described above) or a technical

solution to achieve benefit as part of other business approaches. So “shaving” the output curve of

locally generated energy being sold for the energy wholesale markets allows exact delivery of the

sold schedules and lowers the need for balancing energy.

Other Local Grid services

As already explained in the context of peak shaving, grid operators are obliged to ensure proper grid

operation according to requirements set up in regulations and technical standards. The conventional

way to do so is to physically build a robust network of grid components including the provision of

sufficient reserves by the generous rating of single components. With the ongoing roll-out of smart

distributed generators, storage systems and controllable loads such technical units are able to

provide further local grid services influencing grid properties at or near the connection points. From

the general perspective batteries together with corresponding power electronics could virtually

contribute to all of the local grid services provided compatibility with the momentary state of charge.

Some of the services suitable to be added to business models include:

Voltage control: By feeding-in reactive power at the grid connection point of some power electronic

unit the voltage at this grid connection point can be increased or decreased, which could contribute

to the overall voltage control strategy of the grid operator in the corresponding grid segment. Power

electronics connected to storage systems (especially inverters) are able to flexibly react to

requirements for reactive power provision. Extensive provision of reactive power in addition to the

main functionality of the power electronic units might require a modest oversizing of the

components and the acceptance of some unavoidable energy losses. This should be taken into

account for drafting respective business models.

Black start: After a global grid failure sufficient generation units are needed to re-start in the

initialization phase of the grid and help to restore nominal grid operation parameters. While

historically grid restauration was realized by large conventional power plants (together with small

stand-alone generators helping them to start) in a scenario with prevailing distributed generation

mainly from PV and wind generation, conventional black start units might not be sufficiently

available anymore. In such a situation smart start services are required from other technical units.

Because battery storage systems are able to feed stored energy back to the grid without needing

own energy supply they are suitable to contribute to the black start reserve.

Some other local grid services being candidates for business options are:

Switchability of technical units (the grid operator is allowed to switch the units on or off as is

required by grid operation)

Availability for grid redispatch measures (e.g. the grid operator might use generation units in

order to replace other generation units)

9 German EEG, for details see below


Version 1.2


Voltage dependent load shedding (some less important loads automatically switch off for

voltages below certain limits)

Provision of short circuit power

Such services are partly mandatory based on technical standards and regulations; partly flexibilities

stay just unused because of the lack of service models or admission for smaller technical units (for

larger technical units, especially TSO procure a range of ancillary services mostly on the basis of

bilateral contracts). Nevertheless the importance of using smart flexible resources in grid operation

will increase in the upcoming years and it is always worth offering such services to grid operators

with the intention to set up bilateral contracts.

In the following sections, “other local grid services” will be addressed only if such services are

suitable to be added to business models. Special emphasis will be put on all aspects leading to a

reduction of grid use tariff since this might become an important element for marketing storage

systems.


Ancillary services provision in general is subject to harmonisation approaches being developed by

ENTSO-E’s Working Groups (entsoe, 2017a). This process runs in parallel to the efforts of

harmonizing the network code on requirements for grid connection applicable to all generators

(entsoe, 2016). Most technical aspects of providing local grid services are directly linked with the

technical requirements set in those EU codes.

Because of the localized and individual nature of local peak shaving measures there are no general

regulations or requirements existing throughout the EU countries. There are some indirect links

between EU law and national measures in cases where aspects of liberalization of the provision of

services or the equal and transparent treatment of single actors might be affected.

3.3.3 National Aspects of Services (Germany)

3.3.3.1 Reduction of grid charges

Certainly the reduction of grid charges is one of the most relevant business options for using the

flexibility of storage systems. Reason for this is a high share of the grid charges in the electricity price

customers have to pay (note that taxes are put on top!). Figure 21 shows the composition of the

power price for households in Germany in 2017 (Thalman & Wehrmann, 2017). There are two

general ways to lower grid charges using battery systems: first the reduction of the capacity charge

by limiting the maximum power and second special load profiles as specifies in certain regulations

described below. First the aspect of limiting the maximum power should be explained.


Version 1.2


Figure 21: Composition of power price for households in 2017 (Thalman & Wehrmann, 2017)

While small private customers normally pay only a basic price and an energy price (depending on the

kWh consumed), most commercial and industrial customers have tariffs with separate energy and

power prices. Figure 22 shows an example for a business tariff of the energy supplier Mainova. Note

that this tariff requires corresponding metering equipment for energy and power.

Figure 22: Electricity tariff for business customers of German utility Mainova valid since 01. July 2016 (Mainova, 2016). The values are the variable energy price for high and low tariff periods, the power price and some management fee.

Prices are given with and without V.A.T.

Usually the power price is determined on the basis of the maximum average power per ¼-h in one

year (other time periods can be defined in the contracts). That means that the power of just one

quarter of an hour in a full year might significantly influence the power price component for the

whole year.

From this situation there results an excellent opportunity for a battery system together with a smart

energy managements system to predict and cut peaks in the electricity demand and lower the power

price component. Since the details for the power price are defined with the contract between

supplier and customer no other rules or regulations have to be met. Unfortunately today this

business option is not applicable for small private customers with mostly just energy meters

installed. Some potential benefits of limiting the grid power also of such customers will be discussed

in following chapters addressing buildings.

Besides the “normal” electricity tariff agreed by supplier and customer there is a number of rules and

regulations in Germany forcing the grid operator to financially honour grid-friendly behaviour. Often

the applicability of such special regulations requires a certain minimum power or energy

consumption, making it less attractive for smaller actors. In any case, service provider seeking for

business models should check applicability of the different options for their technical situation.


Version 1.2


Avoided Grid Use according to § 18 StromNEV

Concept:

Decentralized generators receive payments from the grid operator for lowering the maximum load in

the distribution grid. Both energy and power payments may be calculated. Note that generators

receiving payments from feed-in tariff (EEG) are exempted.

Technical Requirements:

No special requirements. For the power payment component corresponding metering equipment is

necessary. Note, that the actual power being fed into the grid at the moment of maximum grid load

is the criterion for this payment. For generators with energy metering only average availability values

are being calculated.

Legal Basis:

Ordinance on Electricity Grid Access Charges – StromNEV (StromNEV, 2016)

Situation April 2017: The German government prepared the draft for a new law

“Netzentgeltmodernisierungsgesetz (NeMoG)” (NeMoG, 2017) which also includes a stepwise

abolishment of the avoided grids use payments. The Federal Council of Germany rejected this draft

arguing besides other aspects that the payments for controllable generators should be retained.

Currently it is not clear what the situation of this payment will be on a medium and long term

perspective.

Relevance for storage business models:

Storage systems could be used to tailor energy fed back to the grid in such a way as to achieve

maximum feed-back during time of maximum grid use. This increases to probability of higher

payments.

Notes:

Estimations showed that for a 5 kWp-PV system with battery storage payments could be in the order

of magnitude of up to 500 Euro per year. The concrete calculation of avoided grid use payments is

rather complicated, a manual for that is given here: (VDN, 2007).

Atypical Grid Use according to § 19 StromNEV

Concept:

Consumers with maximum grid load happening during times of low total grid load are eligible of

reduced grid tariffs.


Own maximum power in period with high grid power must be less than 30 % of overall own

maximum power. Minimum power reduction: 100 kW. Minimum limit of payments: 500 Euro.

Legal Basis:

Ordinance on Electricity Grid Access Charges – StromNEV (StromNEV, 2016)

Situation December 2016: The German regulatory body (Bundesnetzagentur) started a consulting

process aiming at the adjustment of the technical requirements



Version 1.2


Certainly only relevant in special cases where for larger loads and a longer time period “atypical” grid

use could be secured.

Notes:

Might be relevant for some industrial consumers, not relevant for most building applications. There

might be room for local pooling solutions in future.

Reduced Concession Fee according to §2 KAV

Concept:

The concession fee is a payment from the grid operators to the communities where the grid

infrastructure is being installed. There exist some special cases where there payment can be reduced

depending on the contract between utility and consumer.


See contractual details, adequate metering equipment required

Legal Basis:

Ordinance on Concession Fees – KAV (KAV, 2006)


Only relevant in very special cases (large loads with more than 30 kW and 30.000 kWh/a).

Notes:

- none -

Control of interruptible loads according to §14a EnWG

Concept:

The owner of a grid connected load that could be interrupted without technical problems allows the

grid operator to switch the contracted load off if needed (with reasonable frequency). For this service

the operator of the load receives a deduction of the grid use fees.


Contracted loads need to be equipped with an independent meter and communication equipment.

Legal Basis:

“Situation April 2017: §14a EnWG foresees that the Government should issue an ordinance clarifying

details of the implementation of this regulation, especially the volume of grid fee reduction and the

technical realization of interruption, metering and communication. Up till now there is no ordinance

existing and grid operators interpret §14a EnWG quite individually”, German Energy Act – EnWG

(EnWG, 2017).


Certainly the lack of a governmental ordinance complicates the design of business models involving

storage systems. The most obvious case of application are chargers for batteries (especially for EV)


Version 1.2


that are flexible regarding the charging schedules. Still uncertain is the question if batteries could be

combined with “interruptible loads” in order to take over the load supply during times of switch-off

by the grid operator or if even deliberate battery discharging could be considered as “interruptible

load” as well.

Notes:

The usual applications for §14a EnWG are electric heaters and heat pumps. To give an example about

the reduction of the grid fees: the German DSO bayernwerk charges a grid fee (energy price) of

2.92 ct/kWh for §14a EnWG devices compared to 6,22 ct/kWh for standard loads without power

metering (bayernwerk, 2017).

Regarding electric vehicles there are pilot projects for charging stations in Germany marketing the

pool of chargers as “interruptible load” (LichtBlick, 2016).

3.3.3.2 Curtailment minimization

“Curtailment” of distributed generation (mostly in the context with renewable) means the reduction

of electric output power below a defined upper power value even though a higher production would

be possible. One frequent situation with curtailment is set by § 9 of the German Feed-in law “EEG”

(EEG, 2016). Operators of PV installation in the power range up to 30 kW can chose between the

(costly) installation of a remote control unit for the grid operator or a technical limitation of the feed-

in power of the PV system at the grid connection point to 70 % of the installed nominal power. The

reason for this regulation is to limit the power peaks from PV installations and increase the grid

capacity for the installation of new PV systems.

For the PV system owner this curtailment might lead to a loss of energy of up to 7 % (von Appen, Braun, Zinßer, & Stellbogen, 2012). PV system owners might avoid this loss by an intelligent energy management involving battery systems and/or controllable loads.

Figure 23 shows an illustration of the “intelligent” operation management of a battery storage

system in order to limit the PV power fed back to the grid.

Figure 23: Intelligent energy management and forecasting allows limiting PV power fed to the grid and increasing own consumption (Barth & Franz, 2013), based on results of (Hollinger, et al., 2013)

From the point of technical standards there is no problem to bundle PV system, battery storage and

local loads for fulfilling the 70 % power limit.

The alternative to the 70 % curtailment regulation is the installation of remote control units being

operated by the local DSO. In cases of bottlenecks or too much power in the grid the DSO may

reduce PV output power (typically in steps of 100 %, 60 %, 30 % and 0 %) by signalling via (mainly)

ripple control receivers. Since PV system owners are getting compensated for the lost energy there is

no business model in redirecting the energy reduction into the storage system.


Version 1.2


Using batteries for the curtailment of PV power fed to the grid is currently incentivized by the

promotional bank of the Federal Republic of Germany KfW in collaboration with the Federal

Environment Ministry within the programme to promote use of energy storage in solar PV

installation. The scheme involves loans and repayment subsidies for energy storage batteries in grid-

connected solar PV systems. Its aim is to improve integration of small-to-medium solar PV systems

into the electricity grid. Besides the limitation to PV installations with a nominal power up to 30 kWp

the key requirement is that the power fed back to the grid must be less or equal 50 % of the total

installed nominal power. This limitation must be guaranteed for the whole lifetime of the PV system

(!) even if the battery is decommissioned. Both battery systems for new and for existing PV systems

are subject of funding. Details regarding the technical requirements as well as the conditions for the

loans and repayments can be found in (KfW, 2016).

3.3.3.3 Other Grid Services

As explained above there are no current business models for smaller and medium size storage

systems based on “other local grid services”. Nevertheless references should be given here about

applicable technical standards and regulations linked to some of the services.

Voltage Control / Local Provision of Reactive Power

Technical requirements:

Modern power electronic circuits in inverters, charge regulators and others allow operation modes

generating reactive power according to set parameters. The phase angle cos φ and the volume of

reactive power, respectively, might either be a fixed value or depend on the momentary total power

of the unit or the local voltage at the grid connection point. Most technical units allow a broad range

of cos φ values even partly allowing the provision of reactive power with the real power being zero

(e.g. PV inverters during night).

Legal basis:

In Germany, technical units to be connected to the public grid need to meet requirements set in

collections of connection rule (“Technische Anschlussregeln – TAR”), which are separated for low

voltage, medium voltage and high voltage grids. The regulation framework itself us currently in a

transformation process merging a multitude of single regulations into comprehensive collections.

The emerging standards will be VDE-AR-N 4100 + 4105 (LV), VDE-AR-N 4110 (MV), VDE-AR-N 4120

(HV) and VDE-AR-N 4130 (transmission) (VDE FNN, 2017).

These standards will define requirements regarding the provision of reactive power by the technical

units. Depending on the size of the unit grid operators can define certain set points or a certain

droop depending on grid voltage or output power. The standards do not address situations where

the operators of the technical units offer extra services based on reactive power provision on top of

the technical requirements from the TAR. It can be assumed that such extra service would not be in

contradiction to the current or future standards.

Black start capability


The current (conventional) black start procedure involves two steps: first the individual power plants

start with only producing sufficient energy for their self-consumption. In step two they receive an

order from the TSO to re-synchronize with the public grid. Thus technical units foreseen for the black

start pool need a communication link to the TSO being independent from the public electricity

supply. Regarding the potential role of battery storage systems in this process there are two options:


Version 1.2


very large battery systems could act like “conventional” generators synchronizing to the grid and

feeding-in power for a certain time. A more appropriate application for medium size batteries is a

combination of such batteries with other generators not having black start capability. In such cases

the battery should store sufficient energy to power up mostly conventional generation units. Such an

approach is currently being tested in a research project “Kickstarter” funded by the German

government, where a 5 MW battery storage system is combined with a combined cycle power plant

(FIZ Karlsruhe, 2016)

Legal basis:

Responsibility for the provision of sufficient black start capacity in Germany has been assigned to the

TSO, which close contracts with appropriate power plant operators. On the basis of the German

energy act (EnWG, 2017) TSO can pay reserve power plants for costs resulting from the provision of

black start capability. Different from other countries (e.g. Switzerland) there is no tendering process

for black start capacities in Germany and individual non-transparent contracts are made.

Notes:

According to the regulatory body (Bundesnetzagentur) there are currently 120 power plants with a

total power of 9,7 GW ready for black start services. A part of these units is acting on the markets,

another part are reserve power plants. The Bundesnetzagentur might decide to keep outdated

(conventional) power plants in the reserve pool, with sufficient black start capacity being one reason

for this. Costs to maintain operability of closed down power plants are rather high, so there might be

room for financing alternative solutions involving storage systems.

3.3.4 National Aspects of Services (Spain)

The literature research revealed no information regarding currently implemented programs for the

promotion of peak-shaving

As explained more in detail in section 3.4.4.2, charges to self-sufficiency referred to as backup

charges (esp. “peaje de respaldo”) or also as self-sufficiency charges (esp. “cargos al autoconsumo”)

have an impact when storage units are used to perform peak load shaving. In short, the consumer is

not allowed to profit completely from being able to perform peak load shaving and lower the

contracted power (power measured at the connection point to the grid) by means of self-sufficiency.

Depending on the self-consumption facility configuration, a power-related fixed charge component is

measured at a total consumption meter for the consumer’s load, or by taking into account the

maximum generation power from the facility’s generating unit. Storage units must be installed so

that they share metering and protections with the generation unit, according to Art. 11.2 Spain’s self-

sufficiency law RD 900/2015.

Time-of-Use Charging

Currently, shifting load peaks is encouraged or fined with 3 different tariffs called peak, flat, off-peak

(spa.“punta”, “llano” and “valle”). These tariffs are not only applied to a distributed generation (DG),

but to every power consumer.

“Supervalle” Tariff

This tariff is regulated in the Royal Decree 647/2011 (Ministerio de Industria, Turismo y Comercio,

2011) and is created for so-called “system load managers”. These are said to be agents offering

electric recharge services for electric vehicles. Two tariff types referred to as super off-peak (spa

“supervalle”) are regulated:


Version 1.2


2.0 DHS10 for generation in low voltage (<= 1kV) and for a contracted power lower than 10

kW.

2.1 DHS for generation in low voltage (<= 1kV) and for a contracted power between 10 kW

and 15 kW.



reduction of grid charges in Spain. The only “benefit” found is to install a configuration which helps

avoiding the previously mentioned additional charges (i.e. the so-called backup charges) applicable

for self-consumption, further explained in section 3.4.4.2.

Cogeneration however, is exempt from these additional charges until 31st of December 2019 when

part of a self-sufficiency facility.


In Spain, there is no central dynamic curtailment or fixed curtailment level for distributed PV like in

Germany (see Chapter 3.3.3.2.). The Spanish regulation builds upon financial motivation of peak

reduction. There is a price for the maximum power consumption / generation of each grid

connection point (based on contracted power, controlled by accordingly power limited fuses).

Nevertheless, under actual regulation batteries can only partly reduce the peak power from a billing

point of view due to hindering measurement point regulation.

3.3.4.3 Other grid services

In 3.3.1 some special grid services have been introduced. Those grid services currently involve no

actual business option but might become relevant in mid-term future. It is expected that this is also

the case in Spain.

Voltage Control in the transmission grid


This service is currently regulated by the Operating Procedure 7.4 (Red Eléctrica de España, 2000). In

this document voltage control is described as requiring a minimum obligatory provision as a technical

requirement for connection to the transmission grid. In addition, providers have to option to offer

additional provision, which is payed by means of regulated prices.

Legal basis:

This service must be provided by:

- Generators: with a registered net capacity equal or higher than 30 MW and with direct

connection, or through a specific evacuation line, to nodes in the transmission grid. Also

included are different generators with a capacity inferior to 30 MW which feed energy at the

same node and that the sum of their capacities is equal or larger than 30 MW.

- Transmission companies and Distribution grid managers: must provide the service with all

possible means and devices under their property which can provide reactive power

management and voltage control.

- Qualified consumers: not linked to an electricity tariff and directly connected to the

transmission grid with contracted power equal or higher than 15 MW

10 DHS stands for Super off-peak time discrimination (spa. “Discriminación Horaria Supervalle”).


Version 1.2


Particularities of the provision of the service can be found in section 6 of the previously mentioned

regulation.

Black Start

There is mention of the development of a new black start service where an obligation of ensuring a

continuous functioning at full activation during a minimum time of two hours (Red Eléctrica de

España, 2014).

3.3.5 National Aspects of Services (Sweden)

In response to the 2012 Energy Efficiency Directive, the Swedish Energy Markets Inspectorate (Ei)

introduced a new regulation aiming to incentivize DSOs to more efficiently utilize their power

system. The regulation is technology-neutral, meaning that the regulator does not regulate the

choice of technology; the DSOs and the market are the ones in charge make the choice of

technology. These incentives were implemented during the 2016-2019 period and are divided in two

parts: a) an incentive to reduce network losses and b) an incentive to increase system utilization by

improving the load factor and reducing cost to the superior grid. Economic incentives for DSOs are

thus created to lower network losses and to reward peak shaving (Wallnerström, et al., 2016).

The increase in system utilization can be achieved by increasing the capacity of the grid through load

mitigation and peak load shaving. To incentivize DSOs to adjust the distribution grid load, the

regulator chose to use the average load factor over a regulatory period in the interconnection points

between the DSO and the superior grid. This is then combined it with the reduction of the cost that

DSOs pay to the higher voltage grid for withdrawal of electricity in that same period.

The DSO can improve its load factor by forwarding incentives to their customers to reward peak load

shaving. Currently, there are few or no incentives for customers to adapt their energy consumption

to the total load system level as their tariffs usually do not depend on the demand and the capacity

of the network. The implementation of network tariffs that vary based on the real output in the

network, could incentivize the customers to even out their energy consumption over time.

Additionally, DSOs can design the tariffs in such a way that it will cost more for the customers to

withdraw electricity from the grid during the hours of the day where the load is high and less when

the load is low (Wigenborg, et al., 2016).



reduction of grid charges. Besides the paragraphs above, mentioning recently implemented

incentives to the DSO’s in order to reward peak shaving,


In 2014, solar power accounted for 0.002% of Sweden’s 39.55 GW of total installed capacity, which is

largely dominated by hydro and nuclear power. This, along with the high degree of interconnection

with neighbouring countries and large storage capacity, makes up for the fact that there is currently

no curtailment of PV in Sweden (Byman & IVA, 2016).



actual business option but might become relevant in long term.


Version 1.2


3.3.6 National Aspects of Services (UK)


Triads and triad avoidance

Triads are a tool available to reduce peaks in demand and the bills of customers with meters that

measure their electricity demand on a half-hourly basis, typically large or medium industrial and

commercial customers, is the Triad charging system. The Triads are “the three half-hours of highest

demand on the GB electricity transmission system between November and February each year,

which are separated from the system peak demand and from each other by at least 10 Clear Days”.

These are used to determine charges for demand customers, typically large or medium industrial and

commercial and payments to licence exempt distributed generation (National Grid, 2017p).

If consumers do not consume electricity in the three “Triad” half-hours, they do not pay Transmission

Network Use of System (TNUoS) charges for the entire financial year. Unpredictability is the main

driver for the reduced demand through the use of Triads. Triads are not known in advance and

National Grid does not provide a forecasting service for them. Instead, Triads are calculated in

March, following the “triad season”, by using settlement data. Since 70% of demand is not half-hour

metered, but instead comes from homes and small businesses, factors such as weather, consumption

trends and daylight-hours are highly influential in the final location of the Triads. Many suppliers

provide forecasting services and National Grid does provide notice of a “tight margin” between

generation and production, to which customers respond by lowering demand thus increasing the

unpredictability of the final Triad half-hours.

On the generation side, there are commercial advantages for distribution-connected generators,

known as “embedded” generators (<100 MW). These are known as “embedded benefits” (Frontier

Economics, 2017):

Avoided transmission charges: smaller embedded generators do not pay generator TNUoS.

Payment element: smaller embedded generators can net their generation against a

supplier’s demand to reduce the value of the supplier’s demand TNUoS charge during the

Triad periods.

These payments meant smaller generators could earn around £45/kW by exporting at times of

system stress. The national regulatory authority in the UK, the Office of Gas and Electricity Markets

(Ofgem), estimated these payments would rise to £70/kW by 2020/21. With such increasing revenue

stream, small generators could bid low in the capacity market, affecting other forms of generation.

The regulator communicated following consultation with industry, a reduction on the payment

between £3/kW and £7/kW over three years from 2018-21 (Coyne, 2017).

Reduction of DUoS Red Band charges

The DUoS (Distribution Use of System) charges are levied by the UK’s regional DNO (Distribution

Network Operator) in order to account for the operation, maintenance and development of

electricity distribution networks. These are paid by the end user to the supplier which in turn passes

them over to the corresponding DNO.

DUoS are determined by geographical location and are categorised in 3 different prices according to

fixed periods of time of the day. The peak period is categorised as “Red Band”, daytime is categorized

as “Amber” and night time as “Green”, where the last two are significantly cheaper than the “Red

Band” period (the energyst, 2016). This is an opportunity for storage to shift electricity consumption

to achieve lower Red Band charges.


Version 1.2



The increase in embedded generation, particularly solar photovoltaic (PV), as well as a decrease in

underlying demand is driving decreasing demand levels. In face of lowering minimum demand in the

summer, some inflexible generators (such as CHP, hydro or nuclear) as well as flexible wind

generation were forecasted to be curtailed in the summer of 2017 (National Grid, 2017k).

National grid currently counts on their currently put in place system operation services to manage

periods of low demand and generation output. The actions taken include use of demand side

management services, reduction of imports and synchronization of additional units to solve voltage

constraints (National Grid, 2017k).



actual business option but might become relevant in mid-term future. Recent publications and

showcases in the context of battery systems show the relevance of this topic also for the UK. As an

example Figure 24 shows grid services that could be provided by batteries which, however, are

discussed in (Feehally, Forsyth, & Todd, 2016) for larger showcase installations only.

Figure 24: Battery energy storage grid services with time scale (Feehally, Forsyth, & Todd, 2016)

Transmission Constraint Management Service

Constraints or bottlenecks on the transmission network are classified as “import constraints”, when

localised generation does not meet demand and “export constraints” when localised demand is

larger than generation, where the electricity flow is constrained by the capacity of the circuit. The

Constraint Management service requires the provider to deliver an agreed output during an agreed

period to help relief this constraints and maintain system security (National Grid, 2013a). Types of

services are:

Capped Output: in an export constraint event on the network National Grid may contract

with a provider to cap the level of generation at a station during the period of the constraint.

For capping the output the provider is paid an agreed fee each settlement period.

Minimum Output: an import constraint could cause the requirement for generation to run at

a minimum level to support the network. For generating the provider is paid an agreed fee

each settlement period.

Option Contract: Where there is less certainty over the timing of the requirement, National

Grid may consider entering into an Option Contract for either a Capped or Minimum Output

At any time during the service period National Grid can instruct a provider to cap their


Version 1.2


output. This instruction must be given within agreed timescales to ensure the generator has

the correct notice.

Legal basis:

During each instruction National Grid will specify the service period (in compliance with submitted

BM Data) and the MW level at which the generation will be capped or collared. Where the output of

a generator is unpredictable, such as a wind farm, National Grid and the generator will need to agree

on a forecast of the output had the generation not been curtailed. The provider is paid an availability

fee (£/SP) for each settlement period where the service is available to be instructed and an utilisation

fee (£/MWh) where the output of the unit is capped or collared (National Grid, 2013a).


The exact way in which a constraint is managed depends on factors including the nature of the flows

on the transmission system, the duration of the requirement, the local level of generation output,

and the local level of system demand. This makes the requirements specific to the location of the

constraint and defined in the Invitation to Tender or discussed during the negotiation of the contract

terms.

Reactive Power Services – Enhanced Reactive Power Tender


Reactive power services include both obligatory and marketed services. Minimum requirements for

the obligatory reactive power service can be found in the Grid Code and include:

Supplying their rated power output at any point between the limits 0.85 power factor lagging

and 0.95 power factor leading at the unit terminals.

Have the short circuit ratio not less than 0.5.

Keep the reactive power output under steady state conditions fully available within the

voltage range ±5% at 400kV, 275kV, 132kV and lower voltages

Have a continuously acting automatic excitation control system to provide constant terminal

voltage control of the unit without instability over the entire operating range of the unit.

Evaluation criteria for participation are available in the Connection and Use of System Code (CUSC)

(National Grid, 2017o).

Legal basis:

Participation is allowed to units which can provide voltage support exceeding the minimum technical

requirement or any other unit which can generate or absorb reactive power and isn’t required to

provide obligatory reactive power service.

A new reactive market will be designed and implemented by the end of 2018/19. The results of two

projects, along with industry engagement, will be used as input to implement such a market: The

Power Potential project, which seeks to investigate how to access reactive power from distributed

providers and Project Phoenix, which explores synchronous compensators as an approach to meeting

requirements for both inertia and voltage control (National Grid, 2017l).

Black start

Technical requirements include:


Version 1.2


Start up the main generating plant (at least one unit/module) of the station from shutdown

without the use of external power supplies.

Energise part of the Network Electricity Transmission System or the Network Distribution

System within two hours of instruction from National Grid.

Accept instantaneous loading of demand blocks, ideally in the range 35 to 50 MW, and

controlling frequency and voltage levels within the range 47.5 to 52 Hz during the block

loading process.

The ability to provide at least three sequential Black Starts.

Back-up fuel supplies, if appropriate, to enable the power station to run for a minimum

duration (3 to 7 days) following a Black Start instruction.

Facilities to ensure that all generating units can be safely shutdown without the need for

external supplies, and can be maintained in a state of readiness for subsequent start ups;

The ability to maintain high service availability on both the main and auxiliary generating

plant (typically 90%)

The reactive capability to charge the immediate Transmission/Network Distribution

System(s).

This and further service information can be found at National Grid’s Black start service webpage

(National Grid, 2017b).

Legal basis:

Black start regulation can be found on National Grid’s webpage. National Grid procures this service

not by tendering but by taking part in bilateral contracts with providers. Any provider which can

meet the technical requirements of the service will be taken into consideration. Studies for

alternative approaches for future system restoration were commissioned by National Grid in light of

the changing generation mix and are available at Energy Networks Association (National Grid,

2015a). In this studies, storage together with renewables were considered as one of these

alternatives to provide the service in reserve of future uptake of storage and forthcoming

government or regulatory intervention.

For the long term (further than two years), National Grid seeks to investigate alternative restoration

approaches such as via an initial spine or restoring demand more locally using distributed generation.

Also, subject to sufficient market liquidity a tender approach could be developed to procure black

start.

3.4 Self-sufficiency and home energy supply


The focus of this “business” approach is storage systems installed in homes with co-existing

generation units like local PV or wind generators. Only smaller systems are under consideration with

“smaller” meaning a typical power range between 1 kW and 30 kW. Nevertheless, the basic concepts

described below are applicable for larger installations as well.

When installing a home generation unit, the owner might want to consume some or all of the

generated energy locally (self-consumption) or feed back some or all of the generated energy. This

choice depends on the one hand on the legal or regulatory situation (e.g. of whether it is allowed to

feed back into the grid), on the other hand the economic aspect (value of own consumption vs. value

of energy fed back into the grid) will be decisive. Depending on the relation between local electricity


Version 1.2


consumption tariff and feed-in tariffs for local generation system owners are either motivated to

increase self-consumption or to fully feed all of the energy generated back into the grid.

Figure 25: Comparison of the retail electricity price and feed-in tariffs for European countries (Tjaden & Weniger, 2016)

Figure 25 shows the relation between retail energy price and feed-in tariff for different European

countries. This comparison gives a first idea about the question whether from the economic point of

view self-consumption might be more attractive than feed-in payments. Note that the feed-in tariffs

shown are examples applicable to specific technical configurations only, which is the same for the

retail electricity price differing significantly from customer to customer. Nevertheless it can be

concluded that for the majority of EU countries self-consumption is a very attractive option for the

owners of DG RES.

It should be noted that sometimes non-monetary aspects influence the decision of the house owner

like the intention of a high level of independence from the public energy supply (“self-sufficiency”).

Quite often the aspect of self-supplying with energy being generated in the own generator motivates

people to engage in distributed generation.


Version 1.2


Figure 26: Self-consumption’s main characteristics (Masson, Briano, & Baez, 2016)

Figure 26 shows a concise summary of characteristics linked to the aspect of self-consumption. This

figure was published in a rather comprehensive IEA-PVPS Task 1 report (Masson, Briano, & Baez,

2016), summarizing details of PV self-consumption policies including aspects of the economic

analysis for different self-consumption concepts. As can be seen in the figure, there are quite a

number of options of how to build self-consumption schemes starting from the simple question of

formal permission and ending with technical details like the time resolution for metering self-

consumption. One aspect of special relevance for the economic evaluation is the question if onsite

self-consumption is accompanied by additional savings/payments, or rather accompanied by the

obligation to pay additional fees or taxes.

In the context of the current study it is important to notice that for situations with net metering the

use of batteries for storing locally generated electricity makes no sense since, from the logical and

financial perspective, the grid acts like a “free-of-charge storage”.

Studies published by the JRC Karlsruhe in (Zucker, 2016) show that the PV self-sufficiency rate is

relatively constant in Europe. For single households the self-sufficiency of 30 % in absence of

batteries increases to 70 % if a 10 kWh battery is deployed (see Figure 27). Size and costs of the

battery increase sharply when trying to increase self-sufficiency beyond 70 %. Costs also increase

when undersizing the battery due to fixed costs.


Version 1.2


Figure 27: The deployment of batteries increases the self-sufficiency rate – result of a study for single households (Zucker, 2016)

The sections below will give a summary about the different national frameworks for the handling of

locally generated / stored energy and will give references to relevant regulations in this context.

A different (and partly complementary) approach is the aggregation of numerous home storage units

in virtual batteries in order to serve aggregation platforms and to provide services like power for

energy markets or balancing services. Because the services themselves (and corresponding

regulatory frameworks) have been described in previous chapters, details will not be repeated here

again. Only aspects of the interfacing of home energy supply systems and those aggregation

platforms will be mentioned below.


Self-consumption of locally generated electricity has been recognized as one promising approach for

fostering the European energy supply transition processes. This will be reflected in the upcoming

version of the Directive of the European Parliament and of the Council on the promotion of the use

of energy from renewable sources (current draft version: February 2017) where especially the need

for setting up a regulatory framework which would empower self-consumers to generate, store,

consume and sell electricity without facing disproportionate burdens is mentioned (European

Commission, 2017). It also requires that collective self-consumption should be allowed in certain

cases so that citizens living in apartments for example can benefit from consumer empowerment to

the same extent as households in single family homes.

Currently the handling of electricity generated by smaller DG is typically regulated by national bodies.

Especially for rather small installations handling and technical requirements differ profoundly from

country to country, reaching from the allowance of plug-in the generation units (the generation unit

needs neither allowance nor additional technical measures for grid connection) to very restrictive

approaches requiring explicit contracts to run grid coupled generation units. For the present context

appropriate business models need to be tailored to the concrete national situation.

One cornerstone in the development of smart business models for home energy supply and storage

systems is the smart meter rollout. Currently the EU aims to replace at least 80 % of electricity

meters with smart meters by 2020 wherever it is cost-efficient to do so. On 30 November 2016, the

Commission published a proposal stating that all consumers should be entitled to request a smart


Version 1.2


meter from their supplier. Smart meters should allow consumers to reap the benefits of the

progressive digitalisation of the energy market via several different functions. Consumers should also

be able to access dynamic electricity price contracts (European Commission, 2017).

In the context of self-sufficiency and home energy supply smart metering systems could be used for

the following additional purposes:

Collect and process all data relevant for local energy management and monitoring

Connect flexible local units to trans-regional operating service providers for entering service

pools

Exchange monitoring, control and operation data with third parties (e.g. grid operator) if

required by regulations (e.g. as precondition to receive certain payments),

Involve the operation of a local communication network to link multiple technical devices in

the house

Serve as a technical basis for forecasting generation and demand

As of today the EU smart meter rollout still is in the starting phase because of a number of parallel

preparation actions, like the national adaptation of rules and regulations, the development of safety

and protection concepts, the development of robust but cost efficient hardware solutions and the

adaptation of the procedures and software for all actors involved (especially utilities and grid

operators).


3.4.3.1 Contractual and legal aspects

The regulation regarding decentralised generation in Germany distinguishes between two general

situations:

Situation 1

Electricity produced by distributed generation is immediately assigned to a third party (often grid

operators), and the owner/operator of the DG unit has no right to consume this energy himself.

For almost all cases where operators of DG / RES units receive payments from feed-in laws (EEG,

KWKG), situation 1 is given and all generated electricity must be (at least financially) fed back to the

public grid. Also for situations with direct marketing of own generation, self-consumption without

compensation measures evidently is not possible.

Situation 2

In all other cases self-consumption is allowed. This right of self-consumption means “real-time”

consumption requiring immediate consumption (or local storage) of generated electricity. The

applicable laws allow a rather dynamic allocation of distributed generators (or even parts of them)

for feed-in payments (situation 1) or self-consumption (situation 2).

Net-metering in Germany usually is not allowed. Probable reason for this is the philosophy of a strict

unbundling between generation and consumption prohibiting a direct financial and logical offsetting

at the local grid connection points. The German regulatory body requires the separate metering and

handling of energy fed-back and consumed (Bundesnetzagentur, 2015). Nevertheless, in the past

some DSO tolerated the installation of single meters without backstop for very small PV installations

(leading to unofficial net-metering situations).


Version 1.2


3.4.3.2 Revenues and Charges

Primary source of revenues from self-consumption in Germany are avoided costs for electricity

consumption. The electricity price for most customer groups exceeds the potential feed-in payments

significantly. The following table shows some typical electricity prices and current PV feed-in tariffs

on the basis of the German feed-in law.

Table 14: Comparison of average electricity price and selected feed-in tariffs for Germany in 2016 (Bundesnetzagentur,

2017b) (Bundesnetzagentur, 2017a)

Average Electricity Price (2016) in Ct/kWh (Excluding V.A.T.)

Private consumers 25,04 (29,80 incl. V.A.T.)11

Small Businesses 21,20

Industries 14,21

Feed-in tariffs (installation end of 2016) in Ct/kWh (Excluding V.A.T.)

<= 10 kWp on buildings 12,31

< 40 kWp on buildings 11,97

< 100 kWp on building 10,71

Others <= 100 kW 8,53

For plant owners of PV it is important to clarify additional taxes and levies they need to pay either in

the case of self-consumption or in the case of receiving feed-in tariffs. So there is an obligation for

consumers of self-consumed PV energy to pay a partial fee “EEG Umlage”, which is a levy to co-

finance renewable generation sold by the German TSO as part of the feed-in law mechanism. PV

systems less than 10 kWp are exempted for the first 10 MWh of self-consumption. This reduced levy

for self-consumption currently is in the range of 2,5 cent/kWh, which is 40% of the full levy.

In many cases it is also necessary to pay taxes for self-consumption. The procedure of how to

calculate the taxes depends on many aspects like the legal status of the system owner, the way the

PV installation has been declared to the finance authority and the purpose of the self-consumption

(e.g. private or business). A rough estimation is: 19% taxes on the number of kWh x 20 cent/kWh.

Similar taxes (except “EEG-Umlage”) also have to be paid for feed-in tariffs with different tax

categories being applicable depending on the status of the system owner. Such categories might be

“Umsatzsteuer” (turnover tax), “Einkommenssteuer” (income tax) or “Gewerbesteuer” (trade tax).

Details about the tax situation go beyond the scope of this paper.

3.4.3.3 Metering and billing

For situations with self-consumption of locally produced energy the metering concept needs to be

designed in a way to register all relevant energy (generated, consumed, fed-in, fed-back) for the time

intervals relevant for billing (which for small consumers is up to one year, for larger consumers 15

min). Figure 28 shows the generic metering concept with meters for demand, feed-back and

generation. For more complex technical concepts (e.g. with a multitude of different generators) most

11 Most private customers can get no refund on V.A.T. , other than business customers


Version 1.2


grid operators accept to substitute values replacing physical meters, if metering values can be

calculated unequivocally. It should be noted that even in cases with 100% self-consumption the

generated (and thus self-consumed) energy needs to be measured for the calculation of “EEG-

Umlage” and taxes.

Difficult situations could occur if besides an increase of self-consumption, battery systems serve

additional services, e.g. the provision of regulating power. In such cases it might become

undistinguishable if a certain local energy consumption from the physical point of view originated

from energy drawn from the grid (requiring the payment of a multitude of taxes and levies), or if it

originally was generated by the local PV installation and is thus exempted from most of such duties.

Details about such implications were discussed in (Hollinger R. , et al., 2016) and (Soyck, Schilling,

Schmidt, & Engel, 2015). The matter still is under discussion in Germany.

Figure 28: Standard Metering Concept for distributed generation and self-consumption (SMA, 2012). A battery could be connected either via DC/DC-converter to the PV plant before the inverter or via DC/AC-converter to the house grid.

3.4.3.4 Other aspects

Between pure “self-consumption” by the plant owner and delivery of the generated energy to

remote consumers via the public grid there is a broad spectrum of modified “self-consumption”

solutions involving third parties and various contractual situations. The common denominator among

these solutions is the saving of fees and taxes by local delivery and consumption of generated energy

with “local” meaning in the same or neighbouring buildings. Tax benefits (electricity tax) could even

be achieved if a near part of the public grid is used. Mostly not using the public grid leads to

significant savings. By supplying locally produced electricity to additional local consumers (typical

situation in multi-storey residential buildings) the share of “self-consumption” could significantly be

increased. Third-party ownership solutions are allowed. More details about this will be given in

Chapter 3.5.

Figure 29 shows the summary from (Masson, Briano, & Baez, 2016) for the self-consumption scheme

in Germany.


Version 1.2


Figure 29: Germany’s self-consumption schemes (Masson, Briano, & Baez, 2016)



During the last years a radical reform of Spanish electricity regulation has been undertaken.

Cornerstone of the reform is the new Power Sector Law 24/2013 (spa. “Ley del Sector Eléctrico”),

approved by the Spanish Parliament on December 26th, 2013. The reform touches on a large number

of issues and, in particular and for the first time in Spain, it regulates self-consumption. The Power

Sector Law does not set specific self-consumption regulations. These have been laid out in the Royal

Decree RD 900/2015 approved by the Government in October 9th, 2015 (Aragonés, Julián, & Alba,

2016).

While the authors of (Aragonés, Julián, & Alba, 2016) state that the decree does not introduce any

taxation on distributed generation but only “foretells a methodology for defining other system costs

and energy policy charges” there was wide and strong opposition to the Royal Decree. According to

the Spain’s Photovoltaic Union (UNEF), the new law requires self-consumption PV system owners to

pay the same grid fees that all electricity consumers in Spain pay, plus so-called ‘sun tax’ (Mariscal

&Abogados, 2016). This “sun tax” is officially referred to as backup charges (esp. “peajes de

respaldo”) or also as self-sufficiency charges (esp. “cargos al autoconsumo”). The applicability of

these charges is addressed in the next section in more detail.

Some important points of the RD 900/2015 regulations (Mariscal &Abogados, 2016) (Ministerio de

Industria, Energía y Turismo, 2015):

• Installations smaller than 10 kW are exempted from the backup charges

• The new law prohibits PV systems up to 100 kW from selling electricity. Instead, their owners

are required to donate the extra electricity to the grid for free

• Systems over 100 kW must register in order to sell electricity in the spot market for the

excess power they generate


Version 1.2


• For PV systems up to 100 kW, the owner of the installation must be the owner of the

contract with the electricity company

• Community ownership is prohibited altogether for all sizes of self-consumption systems

• Permissions need to be obtained before installation takes place. Every grid-connected

electricity system needs authorization from its electricity supplier and the Spanish

Government

• The installation of storage units is explicitly allowed as long as they are installed with the

corresponding regulated protection and that they share a metering system with the

generating unit. This is, between the generating unit and the meter only the storage device

may be installed, not any kind of load.

Although the installation of storage units is allowed, there are barriers for their use in context of self-

consumption. Battery owners cannot profit completely from being able to reduce the maximum

power they have under contract with their utility. Since the largest part of the Spanish residential

energy bills is related to the contracted power rather than the actual electricity use, this makes it

harder for battery owners to recoup the cost of their investment. Figure 30 summarizes the main

characteristics of self-consumption in Spain.

Figure 30: Main characteristics of self-consumption in Spain (creara Energy Experts, 2016)


Specifics are set in the Royal Decree 900/2015 approved in October 9th, 2015. According to Art. 2, the

regulation applies to any facility connected in an internal circuit even when there is no feed-in to the

transmission or distribution grids at any moment. On the other hand, it is not applicable to isolated

facilities and generators used in special circumstances. The regulatory structure is presented in

Figure 31 below (Aragonés, Julián, & Alba, 2016). The generation facility is in a different circuit than

the load. Energy and power (i.e. maximum hourly energy flow in a given period) are metered for the

whole facility and generation and load circuits with simplifications for smaller producers. M1

measures the consumption from the grid (and the feed in from the facility), M3 measures the total


Version 1.2


generation from the facility and M2 measures the total consumption of the consumer (this is M2 plus

M3).

Grid tariffs are charged according to the meter M1 (energy exchange with the grid), while other costs

like system costs and so called policy charges are paid according to the M2 meter readings,

determining the local consumption. Note that both energy and power values are relevant for the

calculation of the charges. From the formal point of view no charges are imposed on the generation

facility, nevertheless self-consumed energy and power is being subject to the “normal” consumption

charges. Meter M2 is optional for all consumers with a load less than 100 kW.

Figure 31: Self-consumption facility layout (Aragonés, Julián, & Alba, 2016)

An in-depth analysis of the calculation and applicability of the charges for self-consumption (esp.

“cargos al autoconsumo”), particularly the yearly fixed charges based on power is provided by

(Krannich Solar, 2016) and (Andreu, 2016). Self-sufficiency charges are divided in fixed (as a function

of power) and variable (as a function of demand and self-consumed energy). Non-peninsular electric

systems have reduction in the for self-consumed energy charges according to Annex III of the Royal

Decree 900/2015.

The variable charge applies to energy generated and self-consumed and thus represents the

difference between the total energy generated and the share of energy which was not self-consumed

and was therefore fed into the grid. Facilities with an installed capacity smaller than 10 kW are

exempt of this charge. The fixed charge power 𝑃𝑐ℎ𝑎𝑟𝑔𝑒 additional to grid tariffs applies to both Type

1 and Type 2 self-consumption. This charge is based on the following formula:

𝑃𝑐ℎ𝑎𝑟𝑔𝑒 = 𝑃𝐴𝑝𝑝𝑙𝑖𝑐𝑎𝑏𝑙𝑒 − 𝑃𝑀1𝑚𝑎𝑥

Where 𝑃𝑀1𝑚𝑎𝑥 is the power applicable for grid tariffs (esp. “potencia a facturar a efectos de aplicación

de peajes de acceso”), which for a settlement period, is the maximum power demanded by the

consumer measured at M1. The first summand 𝑃𝐴𝑝𝑝𝑙𝑖𝑐𝑎𝑏𝑙𝑒 refers to the power for applicable charges

(esp. “potencia de aplicación de cargos”). This term is calculated according to three different cases

depending whether the consumer has meter M2 installed and the existence of a storage device in

the facility.

Case A: M2 meter installed

In this case 𝑃𝐴𝑝𝑝𝑙𝑖𝑐𝑎𝑏𝑙𝑒 is to the power which corresponds to the power applicable for grid tariffs if

this were to be measured at M2. This means that:

𝑃𝐴𝑝𝑝𝑙𝑖𝑐𝑎𝑏𝑙𝑒 = 𝑃𝑀1𝑚𝑎𝑥 + 𝑃𝑀3

In this case then fixed charge power is equal to the power measured by M3 at the period where the

power applicable for the grid tariffs was measured. This is clearly not necessarily the time where the

maximum generation from the solar array occurred.


Version 1.2


Despite there is no mention of storage for Case A, if M2 is installed, then the consumer is encouraged

to install storage in order to reduce the power measured by M2 by reducing the maximum

generating power from the solar array.

Case B.1: No M2 meter installed, no battery

In this case 𝑃𝐴𝑝𝑝𝑙𝑖𝑐𝑎𝑏𝑙𝑒 is to the power which corresponds to the power applicable for grid tariffs if

this were to be measured at M1. This means that:

𝑃𝐴𝑝𝑝𝑙𝑖𝑐𝑎𝑏𝑙𝑒 = 𝑃𝑀1𝑚𝑎𝑥

Consequently, no fixed charges on power apply in this case since 𝑃𝑐ℎ𝑎𝑟𝑔𝑒 is zero. A consumer with a

solar array and without a battery should not install the M2 meter in order to fall under this case and

avoid the fixed charges on power.

Case B.2: No M2 meter installed, battery installed

In this case, the power which corresponds to the power applicable for grid tariffs plus the maximum

generation power in the settlement period are used to calculate 𝑃𝐴𝑝𝑝𝑙𝑖𝑐𝑎𝑏𝑙𝑒. This means that:

𝑃𝐴𝑝𝑝𝑙𝑖𝑐𝑎𝑏𝑙𝑒 = 𝑃𝑀1𝑚𝑎𝑥 + 𝑃𝑀3

𝑚𝑎𝑥

Therefore, the fixed charge power 𝑃𝑐ℎ𝑎𝑟𝑔𝑒 will be equal to the maximum generation power

measured at M3. This is the worst case scenario since both the maxim generation power and the

maximum power measured for grid tariffs are used.


The self-consumer must be the owner of the system. Figure 32 shows the summary from (Masson,

Briano, & Baez, 2016) for self-consumption schemes in Spain.

Figure 32: Spain’s self consumption schemes (Masson, Briano, & Baez, 2016)


Version 1.2




Self-consumption of PV electricity is allowed in Sweden. Since 2016 the Swedish government

negotiates measures to reach the national target of 100% renewable energy supply by 2040. Part of

this framework is the intention to make small-scale electricity production and self-consumption

easier, especially for PV systems. This started with excluding systems of 255 kW or less from the

Swedish energy consumption tax when energy is self-consumed. There are current plans to reduce

this tax by 98% for generators over 255 kW thus effectively cancelling the tax for all solar power

systems. This new regulation is about to start in November 2017 (Bellini, pv magazine, 2017).

In addition the Swedish government signalled plans to implement regulatory changes that could

allow homeowners to install PV modules without first obtaining a special permit.


No national net-metering system exists. However, several utilities offer various agreements,

including net-metering for the excess electricity of a micro-producer (Lindahl, 2015).


Sweden has introduced a support system to facilitate the deployment of home energy storage

systems in 2016 (Steel, 2016). The scheme started in November 2016 and covers up to 60% of the

system costs, up to a maximum of SEK 50,000. Under terms of the scheme, financing can go towards

the battery, wiring, control systems, smart energy hubs and installation work for houses with solar

PV systems. The support scheme especially targets at private PV system owners dealing in PV for self-

consumption.

Figure 33 shows the summary from (Masson, Briano, & Baez, 2016) for the self-consumption

schemes in Sweden.

Figure 33: Summary of Sweden’s self consumption schemes (Masson, Briano, & Baez, 2016)


Version 1.2




Self-consumption in the UK is allowed. In October 2015, the UK government announced a change in

its self-consumption scheme with a major decrease of the generation tariff.

According to (Labastida, 2017) residential solar system can currently access the following revenue

streams:

• Generation tariff: This is paid for every kilowatt-hour generated, regardless of its

destination. It is currently set at £0.0414/kWh and is indexed to the UK inflation rate.

• Export tariff: In theory, this is paid for the electricity exported to the grid. For the time being,

the government assumes that half of the kilowatt-hours generated are exported for

installations smaller than 30 kW. Currently, the export tariff is set at £0.053.

• Self-consumption: This is the customer’s bill reduction due to the avoided electricity

consumption from the grid. In a northern European country, residential customers are

typically only able to use about 20%-30% of the electricity produced by their own solar

system without any storage or significant behavioural changes. Assuming 20% self-

consumption and an electricity tariff of £0.12/kWh, a solar system owner would save the

equivalent of £0.024/kWh generated.

During the last months there were intensive discussions in the UK about a solar tax hike resulting

from a business rate hike for self-consumption of rooftop solar power. According to (Solar Trade

Association, 2017) there are around 44,000 micro generators in the UK who currently pay no

business rates on their solar and who face a nasty shock with the rate rise. The same source also

reports uncertainty about the domestic solar VAT and the VAT treatment of storage.


There are a number of “Code of Practice” documents addressing metering of circuits for different

purposes. Those documents can be found on (ELEXON, 2017b). As an example Figure 34 shows a

typical metering concept for smaller generation installations.

Installations with a total installed capacity of 30 kW or less are not required to have an export meter

to receive feed-in tariff export payments. Instead the export payments can be deemed (ofgem,

2017).


Version 1.2


Figure 34: Schematic diagram of a combined Import and Export Meter. The meter could be either one joint measuring unit or two separate meters for import and export (ELEXON Limited, 2011)


Figure 35 shows the summary from (Masson, Briano, & Baez, 2016) for UK’s self consumption

schemes.

Figure 35: The UK’s self-consumption schemes (Masson, Briano, & Baez, 2016)

3.5 Building integration

3.5.1 Description of purpose

Using storage systems in buildings is similar to the business case of self-sufficiency and home energy

supply explained in the previous chapter. Most of what has been described above also bears

relevance for building applications but is not repeated here. To differentiate between “home energy


Version 1.2


supply” and “building energy supply” use cases for this Deliverable, the following assumptions are

made:

In the context of “building integration” multi-family or multi-purpose buildings will be

considered, with the owner of the building mostly not being tenant at the same time.

There are multiple metering points in the building relevant for billing behind the one grid-

connection point of the building.

There is a local grid within the building logically located before the billing-relevant meters

but not being part of the public grid.

The storage system and generators in the building often belong to (or are operated by) third

parties. Differing from the more “simple” situation of typical home systems, there are a

number of options regarding the contractual situation between the system owner, the

building owner and the tenants in the building. Especially this aspect will be addressed in the

present chapter.

There are often building management systems available, which could be adjusted to include

operation management of storage systems as well.

Electrical storage systems in buildings could be used for a number of purposes:

Interim storage of locally generated electricity (from RES or CHP) and increase of self-

consumption / self-sufficiency.

Increase of the flexibility of CHP units by decoupling times of electricity generation and

electricity demand (e.g. by shifting electricity delivery to time with high electricity

load/price).

Integration of the battery into the building management system and interfacing to higher

level energy management systems (see Figure 36).

Backup system for powering essential house appliances in case of grid failure (this aspect is

of lower priority in the present context since backup functionality of the battery mostly

prohibits a flexible use for other purposes).

Figure 36: Architecture model of linking the battery management to building or district management services developed by the H2020-ELSA project (Stöhr, 2015)

A special aspect in the context of services that could be provided by battery systems for the electrical

building supply is the limitation of the maximum electrical power assigned to the connection point

with the public grid. Owners or builders of new houses wishing to increase the maximum power of

the grid connection have to pay for this (labour, hardware and planning among others). The price is

individually determined by the grid operator and might be in the order of magnitude of some


Version 1.2


thousand €12 for just upgrading an existing connection. In cases of only short-term need of the

maximum power (like it is the case in quick chargers for Electric Vehicles (EV)) smart energy

management involving electrical storages can lower the maximum connection power required and

saves extension costs.


Up until now, the new innovative opportunities for using electric storage systems in buildings are

only vaguely reflected in the EU regulation. In (European Commission, 2016) the EC recommends:

“Innovation and new technology also make it possible for buildings to support the overall

decarbonisation of the economy. For example, buildings can leverage the development of the

infrastructure necessary for the smart charging of electric vehicles also provide a basis for Member

States, if they choose to, to use car batteries as a source of power. To reflect this aim, the definition

of technical building systems should be extended.”

Certainly this philosophy applies to all kinds of batteries.

There are no specific EC regulations addressing the building integration of storage systems leaving

the multiple general standards (especially about safety and standardisation matters) applicable to

batteries and buildings. To give an impression about the scope of the standards and regulations,

Table 15 shows a collection of applicable standards for batteries in Germany, mostly being

harmonized European regulations. Some of these still were drafts at the time of the investigation.

Table 15: Standards and regulations for battery systems in Germany (Wille-Haussmann, Hollinger, & Freiberger, 2017)

12 Example from Austria: existing connection: 3x25A, costs for 3x35A: 1000 €, costs for 3x50A: 5000€ (Source: https://tff-forum.de/viewtopic.php?f=9&t=14018)


Version 1.2



3.5.3.1 Tenants’ electricity supply concepts (general)

One of the most relevant business opportunities of electric storage systems in buildings (combines

with local electrical generators) in Germany are so called “Mieterstromkonzepte” – “tenants’

electricity supply concepts” or “neighbour solar supply model”. The intention behind is a local

consumption of locally generated electricity within the same building (or connected buildings).

During the last years this aspect received more and more public attention driven by decreasing feed-

in tariffs for RES energy and the need to develop new business options for smaller and decentralised

generations together with the goal to relieve the public grid from peak powers generated by

fluctuating generation.

Only recently the concept of “Mieterstrom” was mentioned in national laws and regulations, so the

latest version of the feed-in law (EEG 2017) enables the German government to establish acts for

supporting “Mieterstromkonzepte” by e.g. treating them equal to self-consumption solutions. As of

the end of April 2017 the German Federal Cabinet accepted the draft for an act on the promotion of

“Mieterstrom” (Bundesministerium für Wirtschaft und Energie, 2017). Corner marks of this act are:

Funding of PV system owners for delivering electricity to other (local) tenants with 2.2

ct/kWh to 3.8 ct/kWh. The funding depends on the plant size and is paid only for new

installations up to 100 kWp.

The electricity price the providers can claim from the tenants must be less or equal to 90% of

the local standard electricity price.

Each tenant still might freely select his/her local electricity supplier (this means, she/he

might refuse electricity supply by “Mieterstrom”).

The payments PV owners receive partly compensate taxes and levies that have to be paid when

delivering electricity to other customers. Nevertheless the free choice of the electricity supplier by

the customers (which can be changed yearly) imposes a significant economic risk on the PV system

owner.

The set-up of “Mieterstromprojekte” offers benefits for several stakeholders in the value generation

chain, as is illustrated in Table 16.

Table 16: Steps in the value generation chain for tenants’ electricity supply concepts - “Mieterstromkonzepte” (Aguilar, 2016)

Stages Task Stakeholders

Building envelope Provision of the surfaces for PV generation

Real estate companies

Electricity generation Planning, installation, financing, M&O of the PV installation

Real estate companies

Electricity delivery Metering point operation, billing, marketing and customer

acquisition, purchasing and delivery of grid power,

customer service

Utilities, cooperatives, real estate companies that are supported in this regard by

various service providers, e.g. for measuring point operation

and billing

Electricity consumption Close of an electricity contract, electricity consumption

Private or commercial final consumers (= tenants)


Version 1.2


The contractual relationships of the players are shown in Figure 37.

Figure 37: Contractual relationship of the players in the “Mieterstromkonzept” (Aguilar, 2016)

There is no general binding regulation regarding the metering concept. Certainly metering solutions

need to allow a mercantilist differentiation between energy consumed from the public grid and

energy produced locally, and a correct assignment of energy volumes to customers participating in

the “Mieterstromkonzept” and those remaining customers of other utilities. Figure 38 shows a

frequently used metering concept for “Mieterstromkonzepte” called “Summenzählermodell”

(“model adding values of single meters”).

Figure 38: Metering concept for houses applying the „Mieterstromkonzept“ (EnergieAgentur.NRW, 2017)

Each tenant receives an individual electricity bill, issued by the operator of the

“Mieterstromkonzept” for tenant 1, 2 and 3, and from the utility for tenant 4. The utility also

determines the difference between local electricity generation and local energy consumption by

subtracting the energy measured for tenant 4 from the total energy consumption from the public


Version 1.2


grid (meter ZNB). This energy volume is charged to the operator of the “Mieterstromkonzept”

(relaying it to his customers).

3.5.3.2 Metering aspects

Most certainly this rather easy metering approach described above will be revised with the upcoming

installation of smart metering systems. By using smart metering systems it will become possible to

exactly determine the energy flows at each instant and so to offer incentives to those customers

adjusting their personal consumption profiles to the momentary supply of local energy.

In the context of metering another aspect might be relevant for the smart energy supply of smaller

customers being connected to the public grid. The actual (and historic) approach of energy

procurement for smaller consumers is to use standardized load profiles (“Standardlastprofile”) for

determining the load profiles that energy traders have to buy at the energy markets or from power

plants. According to the recent Electricity Network Access Ordinance (Bundesregierung Deutschland,

2016) consumers with up to 100 000 kWh yearly consumption are handled using “typical” load

profiles defined for certain customer groups (e.g. trade, households etc.). In such a case the real

(physical) consumption profiles (meaning: the distribution of consuming a certain amount of energy

over time) has no relevance at all for the balancing group manager and for the purchase of

electricity. Creating residual load profiles by “Mieterstromkonzepte” cannot be mapped with the

system of standardised load profiles and will indirectly lead to higher demand of balancing power.

Only with the transition process from conventional Ferraris meters and annual meter readings

towards a time-related measuring and billing of load profiles reasonable solutions serving both the

building supply aspect and the compatibility with the national supply system will be achieved. The

German Government together with the regulatory body “Bundesnetzagentur” are currently about to

set the required framework conditions for this.

3.5.3.3 Legal requirements

Service providers of “Mieterstromkonzepte” have to fulfil a number of legal requirements

summarized in Table 17.

Table 17: Legal requirements for setting up “Mieterstromkonzepte“.

Duty Description Applicability

Allowance to act as energy supplier (§ 3 Nr.18 EnWG, §5 EnWG)

Parties selling electricity to others are mostly automatically legal energy suppliers (“Energieversorger”) and need registration with the corresponding offices.

In most cases with a local distribution grid (e.g. within houses) owned by the selling party registration is not needed. Nevertheless the formal status of “Energieversorger” remains valid (leading to other duties).

Contracts on electricity supply

There is a number of requirements regarding the formats and the content of contracts and billing documents (§§40-42 EnWG), including a declaration about the origin of the electricity (§78 EEG 2017).

Fully applicable.

Reporting to TSO and regulatory body

Any electricity delivery to a final consumer needs to be reported to TSO (yearly according to § 74 Satz 1 EEG) and additional data need to be send to the regulatory body (“Bundesnetzagentur”)

Fully applicable


Version 1.2


according to §76 EEG

Payment of partial EEG levy

According to §60 Abs. 1 EEG a special levy has to be paid (details are given in 3.4.3.2)

Fully applicable.

Mid-term changes might be possible if political decisions change.

Allowance for supply according to tax law

According to §4 StromStG a fiscal allowance is needed issued by the chiefs customs office.

Tax issues depends strongly on the details of the corresponding business model and a number of exception (e.g. §1a Abs. 1+5 StromStV or §9 Abs.1 StromStG) might be applicable. An individual agreement with the customs office regarding the allowance and applicable tax reliefs is recommendable.

Note that a new Electricity Tax Act is under preparation, besides others clarifying the tax exemptions for batteries and EV (expected for beginning of 2018).

Payment of taxes

Depending of the concrete details of the business model and the technical realisation, tax payments have to be made. One especially relevant tax might become the electricity tax (“Stromsteuer”, currently 2,05 ct/kW), which however becomes relevant only for larger PV installations (2 MW).

Energy Trader registration

According to EU law (REMIT13) registering as energy trader with the EU might become necessary.

Currently it is not clarified if this regulation is applicable to (small) providers of “Mieterstrom”. In case of doubt the regulator (“Bundesnetzagentur”) should be contacted.

Loss of business tax reliefs of real estate companies

Real estate companies receive tax reliefs if letting of flats is the exclusive business model. Receiving payments for electricity delivery leads to the loss of such reliefs.

This is a serious problem and main reason for real estate companies in Germany to not engage in decentralised RES generation and marketing of green electricity. Up till now political discussions brought no change. A work-around is the formation of some new subsidiary company.

Other requirements

There are numerous technical requirements that need to be fulfilled by the owners/operators of systems generating electricity and being able to feed into the public grid.

Applicable case by case.

The building integration of RES systems with “Mieterstromkonzepte” might be helpful in fulfilling

requirements the context of the energy-saving regulation “Energieeinsparverordnung EnEV”

(Bundesregierung Deutschland, 2015). This regulation defines upper limits to the primary energy

demand of buildings and measures to reach these limits. Electricity generated by RES generation

might (to a certain extent) be offset against the energy demand if the energy is generated and

consumed locally. Thus a proof of set up “Mieterstrommodelle” might contribute to the fulfilling of

the requirements of the EnEV.

13 Regulation on wholesale Energy Market Integrity and Transparency


Version 1.2


Some of the German Federal State issue local incentives to support “Mieterstrom” projects.

3.5.3.4 Building connection to the grid

As explained above battery systems might help to lower the costs assigned to the electrical grid

connection of newly built houses or omit costs for upgrading existing grid connections. In Germany

there are two types of charges raised cumulatively in relation to the grid connection of buildings: (a)

the real costs of the grid operator for building / reinforcing the connection infrastructure and (b) so

called “building costs surcharges” (“Baukostenzuschuss”) contributing to the general grid

enhancement as defined by the low voltage connection ordinance (Bundesregierung Deutschland,

2016). The volume of both types of charges depends on the power for connection or reinforcement,

respectively.

In Germany the typical connection power for dwelling houses is 14.5 kW per household (34 kW with

electric water heating) often being realised as 3 x 35 A connections for a single flat and 3 x 50 A or

3 x 63 A for houses with three flats. In case of operating charging stations for EV (with typical

charging powers in the range of 10 to 20 kW) the power limit for both house loads and EV charging

might be reached quickly and either a very restrictive load management or an extension of the grid

connection power becomes necessary. Using batteries allows temporarily supplying loads exceeding

the maximum connection power and avoids costs for upgrading the electric house connection.

An example for grid connection costs in Germany can be found in (MITNETZ STROM, 2017).

Connecting a house to the distribution grid cable costs about 537 € for up to 100 A and 908 € for up

to 250 A. Cabling for the higher power leads to 7 €/m additional costs.


The main aspects regarding self-consumption have been presented in 3.4.4. In that section, Figure 30

compares the situation of “pure” self-consumption and parallel self-consumption and selling.

Figure 39 shows the results for Spain residential consumption using a case study of a 30 kWp PV

system placed in an office building in Madrid.

Figure 39: Case study results for commercial segment applications (full self-consumption) for a 30 kWp PV system placed in an office building in Madrid (creara Energy Experts, 2016)


Version 1.2


The following barriers for implementation have been identified by the authors (please refer to Table

18 for some more details):

• Customers have to pay fees

• Laborious legal procedure (around 7 months) which are the same for every system (implying

higher costs for smaller systems)

• Multi-family and office buildings have the same problem with more than one company /

tenant: consumer and owner of the system have to be the same legal entity, the only option

for commercial businesses is to use the PV electricity for common spaces or to select one of

the tenants to be authorized for self-consumption and injecting excess energy to the grid by

selling to some pool and paying generation tax.

Table 18: Barriers for self-consumption in Spain (creara Energy Experts, 2016)

In this context, the more general barriers for the PV sector in Spain are considered in Table 19.

Table 19: Barriers for PV sector in Spain (creara Energy Experts, 2016)


Version 1.2



Basic information about self-consumption has been given above in Chapter 3.4.5. Note that Figure 33

explains self-consumption schemes for larger installations as well thus involving building installations

exceed the size of PV home systems.

There were no measures for BIPV development in 2015 in Sweden (Lindahl, 2015). A literature

research revealed no information regarding tenants’ electricity supply concepts (in Germany referred

to as “Mieterstromkonzepte”) delivering locally generated PV energy to local third party consumers.


A number of details regarding the business options for self-consumption in the UK have been given in

3.4.6.

The typical self-consumption business model currently involves only one entity

investor/operator/consumer, leading to “pure” self-consumption. While in the past the typical

business case was primarily based on FiT revenue, current investments in PV are based on self-

consumption business models.

No special regulations or business cases could be found targeting at tenants’ electricity supply

concepts (in Germany “Mieterstromkonzepte”) delivering locally generated PV energy to local third

party consumers. Commercial offers either address intelligent energy management for one consumer

(either private or commercial) or closing contracts to deliver energy to customers via the public grid.

Commercial rooftop solar has historically been only a small part of the market within the UK, unlike

similar markets in Europe as France and Germany. According to (Solar Trade Association, 2016) this is

partly due to structural issues in the market (high prevalence of rented commercial buildings and

relatively few owner-occupied commercial buildings) and the stop-start nature of the subsidy

schemes.

The authors of (Solar Trade Association, 2016) identified a number of barriers and recommendation

for supporting PV installations and business models, also relevant in the present context of

integrating PV systems into building energy supply systems. Such barriers are:

Enable efficient grid connections (many developers report that DSOs are rejecting connection

requests due to a lack of available capacity, even in spite of solutions with grid operator-

controlled export limiters or high on-site usage).

Accurate valuation of exported electricity (for smaller installations it is currently impossible

to set up commercial arrangements with energy suppliers for a reasonable time span).

Provision of a level playing field for clean energy (many benefits of clean energy are not

monetised while attractive frameworks exist to support e.g. energy efficiency).

Reform the market charging and market arrangements (it is necessary to adjust the

electricity markets to the developments of the last 10-15 years).


Version 1.2


4. Important Regulatory Aspects for the Use Cases

In the previous chapters an analysis about regulatory frameworks and market rules carried out for

different business concepts has been given. It is necessary to summarize the most relevant

regulatory aspects and potential barriers for the implementation of business concepts for the Use

Cases in the NETfficient project. This analysis will be carried out individually for the single Use Cases

and is leading to a “Short List” of regulatory framework aspects and market rules. The combined

analysis of social, socioeconomic and legal/governmental impacts (PESTEL analysis) is part of the Use

Case description of Deliverable 6.4.

4.1 Use Case 1: MV-HESS

From a regulative perspective, in Use Case 1 a stand-alone storage with a grid connection point to

the medium voltage grid and a ¼-hourly bidirectional measurement is charged and discharged via the

public grid in different use-cases. Table 20 gives an overview about the purposes of the Use Case and

the most significant regulative aspects.

Table 20: Purposes of Use Case 1 and their regulative aspects

Purpose Legal/market aspect Chapter

Instantaneous Reserve

Market not implemented yet in the countries considered. Provided by rotating masses (physically). Could be relevant in future and as such EU recommendations for its implementation as a future service are already published.

3.2.1

Frequency Containment Reserve

Germany: Participation in the Primary Control Reserve (PCR) is common for battery energy storages. It is possible to use degrees of freedom to stabilize SoC while providing PCR. The battery has to be able to provide full PCR for 30 minutes in each direction in Germany. This is twice as long as in other countries and increases investment costs for a battery storage providing PCR significantly.

Spain: There is no market for primary regulation and its provision is mandatory for all connected generators. Potentially battery energy storages could still be used to provide the FCR and take over the mandatory provision from the power plant operator at the same grid connection point or via bilateral contracts.

Sweden: The FCR product FCR-N tendered in Sweden is very intense in battery usage, but results in low revenue. Applications known in tandem with other technical units. Participation in FCR-D in Sweden potentially results in a low degradation of the battery and adequate revenues (Annex 2 and Annex 3).

Great Britain: Regulation has been adapted to the needs of new technologies like battery energy storages. The most relevant product is Enhanced Frequency Response (EFR) but provision of dynamic Firm Frequency Response (FFR) is still interesting.

3.2.2

FCR: GER:3.2.3.1 SPA:3.2.4.1 SWE:3.2.5.1 UK:3.2.6.1

Integration into Balancing Group / Balancing

BESS potentially can be used to minimize deviations (between predicted and realized energy generation/load) within a balancing group and/or provide their (short-time) flexibility at an intraday

3.2.1


Version 1.2


Energy market to balancing groups of third parties.

The potential revenues seem to be insufficient for a stand alone business model, but the service could be provided as secondary service.

Peak Shaving (Load & Generation)

Peak Shaving can be relevant behind the grid connection point to the public grid.

Germany: Several regulations could be identified that could be used to make/enhance a business model by providing peak shaving of load. Peak Shaving for generation is especially relevant for small-scale batteries, due to limited feed-in power for PV home systems. The charging of the battery to avoid curtailment of wind and PV (due to a grid bottleneck) can be an interesting option in special locations or in future scenarios. A peak shaving on DSO level is only interesting in special cases (see Avoided Grid Use “vermiedene Netznutzungsentgelte” in Germany).

For the other countries no regulation for a peak shaving business-model could be identified.

Great Britain: The power system recently started to face periods of low demand and high generation during summer. When curtailment is considered it is directed to inflexible generation such as nuclear, CHP, hydro and also to flexible wind generation, not PV.

Sweden: No current need and therefore no wide-spread applications for peak-shaving were found. Recently, incentives for an efficient use of the grid have been put in place. These are expected to be forwarded by the DSO’s to their customers to reward peak load shaving.

Spain: No mechanisms put in place which reward peak-shaving. On the contrary, additional charges for self-consumption hinder potential benefits for the consumer (see Table 21).

3.3

Issues due to rapid volatility of RE

No regulation could be identified that makes this service a business model. The speed of volatility seems to be of no relevance for the central European case.

-

Black Start The black start capability of BESS is interesting; however, no transparent market / tender could be identified. Instead, bilateral contracts have to be negotiated with local TSOs. A transparent and fee from discrimination market should be striven for.

GER:3.3.3.3 SPA:3.3.4.3 SWE:3.3.5.3 UK:3.3.6.3

4.2 Use Case 2: Homes

From a regulative perspective, in Use Case 2 a PV home storage system (generation, storage and

load) behind a grid connection point to the low voltage distribution grid with a ¼-hourly bidirectional

measurement or a yearly bidirectional measurement is charged and discharged via the public grid in

different use-cases. Local PV generation is consumed directly or through a storage device (battery,


Version 1.2


second-life battery or hydrogen storage). Table 21 gives an overview about the purposes of the Use

Case and the most significant regulative aspects.



Self-consumption

Depending on the retail electricity price, self-consumption might be more attractive than feed-in payments. If besides an increase of self-consumption, BESS serve additional services such as regulating power, it might become undistinguishable if a certain local energy consumption from the physical point of view originated from the grid (requiring the payment of a multitude of taxes and levies) or if it originally was generated by the local PV installation and is thus exempted from most of such duties.

Germany: Net-metering usually not allowed. Primary source of revenues are avoided costs for electricity consumption, also reduced levies are paid (“EEG Umlage”). In many cases it is also necessary to pay taxes for self-consumption estimated as: 19 % taxes on the number of kWh x 20 cent/kWh. Delivery of locally produced energy to other local consumer is allowed.

Spain: The additional charges for self-sufficiency hinder the potential savings, which self-sufficiency facilities could achieve by generating own electricity and lowering the power measured at the connection point with the grid (i.e. the contracted power with the supplier).

Sweden: Systems of 255 kW or less are excluded from the Swedish energy consumption tax when energy is self-consumed. Several utilities offer various agreements, including net-metering for the excess electricity of a micro-producer. Recent support scheme for PV system owners covers up to 60% of the system costs, up to a maximum of SEK 50,000.

Great Britain: Present revenue streams include the avoided electricity consumption from the grid plus a generation tariff paid for every kilowatt-hour generated, regardless of its destination, and an export tariff, paid for the electricity exported to the grid.

3.4


See Table 20 3.3

Batter Backup Power

Backup power in face of power outages is one of the most common uses for batteries installed at homes. There are no mayor legal implications for this particular use, an aggregated use may enable the use of battery for a Black Start service (see Ancillary Services purpose)

-

P2P electricity trading

Solutions for P2P electricity trading are already put in place in some countries like Germany and the Great Britain; however, a large scale implementation of P2P electricity trading seems unlikely in the short-term. P2P business models are often economically unattractive, due to high cost for grid usage and high

3.1.2


Version 1.2


transaction costs.

Aggregated Trading

The main barrier is the lack of a clear energy aggregation regulatory framework, starting from the EU level (see Figure 5).

The low absolute difference between high and low price times at electricity wholesale markets in central Europe make the active usage of the aggraded flexibility difficult from a economic point of view. Additionally, especially for small consumers, generators and storages the regulative barriers for high-resolution billing (dynamic tariff) are significant (e.g. syntactic load profiles).

3.1.2

Aggregated Ancillary Services

See Table 20, particularly FCR. Services where (aggregated) demand side flexibility takes a role should also be considered. Other services such as Black Start and Synthetic Inertia might become relevant in the long-term.

Great Britain: Balancing services such as STOR, Fast Reserve and Demand Turn-Up allow aggregation (see 3.2.6.1).

Sweden: Minimum bid sizes for FFR-A and FFR-M may be high for some participants (5MW-10MW)

Spain: for the case for Secondary and Tertiary Regulation, the minimum bid size (10 MW) may be high for some players; however aggregation is possible for units of the same scheduling unit and control centre.

3.2

Other: GER:3.3.3.3 SPA:3.3.4.3 SWE:3.3.5.3 UK:3.3.6.3

4.3 Use Case 3: Buildings

From a regulative perspective, in Use Case 3 a PV storage system (generation, storage and loads)

behind a grid connection point to the distribution grid with a ¼-hourly bidirectional measurement

and individual unidirectional ¼-h measurement at all loads and the generation is charged and

discharged via the public grid in different use-cases. Local PV generation is consumed directly or

through a battery. Table 22 gives an overview about the purposes of the Use Case and the most

significant regulative aspects.



Energy supply to local (third party) consumers and own consumption

See P2P electricity trading in Table 21. The difference is that P2P behind a grid connection point (P2P between flats in a building), does not use the public grid and therefore is avoiding many grid charges/levies, making the business case potentially more attractive

See Table 21

Germany: The tenant’s electricity supply concepts in Germany (ger. “Mieterstromkonzepte”) allow local consumption of locally generated electricity within a building or connected buildings. There is no general binding regulation regarding the metering concept and tenants still might freely select his/her local electricity supplier (i.e. refuse supply of electricity by “Mieterstrom”.

3.5.4

3.5.3.1

3.5.4

3.5.6


Version 1.2


Spain: Community ownership is prohibited altogether for all sizes of self-consumption systems. Consumer and owner of the system have to be the same legal entity, the only option for commercial businesses is to use the PV electricity for common spaces or to select one of the tenants to be authorized for self-consumption and injecting excess energy to the grid by selling to some pool and paying generation tax.

UK: Commercial rooftop solar has historically been only a small part of the market within the UK; this is partly due to structural issues in the market (high prevalence of rented commercial buildings and relatively few owner-occupied commercial buildings) and the stop-start nature of the subsidy schemes.


See Table 21

Germany: Real consumption profiles have no relevance to the BRP when standardized load profiles are used to handle customers (<100 000 kWh). Creating residual load profiles by “Mieterstromkonzepte” cannot be mapped with the system of standardised load profiles and will indirectly lead to higher demand of balancing power.

3.4.3.3

Battery Backup Power

See Table 21 -

Aggregated Trading

See Own Consumption in this table.

See Table 21

-

Aggregated Ancillary Services

See Table 21 -

4.4 Use Case 4: Storage for Street Lighting

From a regulative perspective, in Use Case 4 a PV storage system (generation and storage) behind a

grid connection point to the distribution grid with a ¼-hourly bidirectional measurement and

distributed switchable loads (street lightning) are operated in coordination. Local PV generation is

fed into the grid directly or through a battery. Table 23 gives an overview about the purposes of the

Use Case and the most significant regulative aspects.




See Table 21 and Table 22 -



Battery Backup See Table 21 -


Version 1.2


Power

Aggregated Trading and Ancillary Services

The minimum reserve power required for bidirectional FCR services which have to be ensured during the whole contracted period could result in a barrier due to battery sizing.

Products differentiated by positive and negative provision such as Firm Frequency Response in Great Britain and FCR-D in Sweden more adequate for this use case.

Germany: The secondary control service offers positive and negative products for peak (Mo-Fr 8a.m. to 8 p.m.) and base periods, which can be adjusted to ensure lighting at night and provide the service.

Other “secondary control reserve” concepts investigated in other countries only offer negative and positive products but not a time differentiation during the day.

Primary: GER:3.2.3.1 SPA:3.2.4.1 SWE:3.2.5.1 UK:3.2.6.1 Secondary: GER:3.2.3.2 SPA:3.2.4.2 SWE:3.2.5.2

4.5 Use Case 5: Thermal Storage Solution for low-temperature Large Volume Heating Requirements

From a regulative perspective, in Use Case 5 a PV storage system (generation and storage) behind a

grid connection point to the distribution grid with a ¼-hourly bidirectional measurement and

distributed switchable loads (thermal storage vessels) are operated in coordination. Local PV

generation is fed into the grid directly. Table 24 gives an overview about the purposes of the Use

Case and the most significant regulative aspects.




When feeding PV production surplus into the grid regulatory barriers considered come into play. See Table 21 and Table 22.

-



Aggregated Trading and Ancillary Services

Regulatory barriers for aggregators in electricity markets may apply (see Table 21).

Flexibility is limited by the relatively low-temperatures needed, which could render the system unsuitable for participation in some control reserves (like the ones categorized under secondary and tertiary control) with minimum required power generally around 5-10 MW.

Secondary: GER:3.2.3.2 SPA:3.2.4.2 SWE:3.2.5.2

Tertiary: GER:3.2.3.3 SPA:3.2.4.3 UK:3.2.6.1


Version 1.2


5. References

Aguilar, L. (2016). The neighbor solar supply model in Germany - "Mieterstrom". Project Report

"PVFINANCING". Brussels: BSW-Solar.

Andreu, F. (2016, 01 15). Cargos al autoconsumo: Como se aplican y como afectan. Blog post.

Retrieved 11 22, 2017, from http://solartradex.com/blog/cargos-al-autoconsumo-como-se-

aplican-y-como-afectan/

APX. (2017). EPEX SPOT in the UK. Retrieved 04 05, 2017, from https://www.apxgroup.com/trading-

clearing/apx-power-uk/

Aragonés, V., Julián, B., & Alba, J. (2016). The new Spanish self-consumption regulation. Energy

Procedia 106 , 245 - 257.

AYESA ADVANCED TECHNOLOGIES. (2015). Research Project NETfficient, Deliverable 1.8.

Barth, B., & Franz, O. (2013, October 22). Results from PV GRID Research for Germany. PVGRID.EU.

bayernwerk. (2017). Preisblatt Netzentgelte Strom. Regensburg: Bayernwerk AG.

Bellini, E. (2017, 03 21). pv magazine. Retrieved 06 23, 2017, from Sweden's plan to reduce tax for

self-consumption by 98% moves forward: https://www.pv-

magazine.com/2017/03/21/swedens-plan-to-reduce-tax-for-self-consumption-by-98-moves-

forward/

Bellini, E. (2017, 04 04). Sweden tops 140 MW of installed PV capacity. pv magazine. Retrieved 11 17,

2017, from https://www.pv-magazine.com/2017/04/04/sweden-tops-140-mw-of-installed-

pv-capacity/

BMWi. (2016). Länderprofil Schweden - Informationen zu erneuerbaren Energien und zur

Energieeffizienz. Berlin: Bundesministerium für Wirtschaft und Energie (BMWi).

Bundesministerium für Wirtschaft und Energie. (2017, 04 26). Entwurf eines Gesetzes zur Förderung

von Mieterstrom und zur Änderung weiterer Vorschriften des Erneuerbare-Energie-Gesetzes.

Retrieved 04 26, 2017, from https://www.bmwi.de/Redaktion/DE/Downloads/E/entwurf-

mieterstrom.html

Bundesnetzagentur. (2015, 11 24). Strombezug von PV Anlagen. Retrieved 04 21, 2017, from

https://www.bundesnetzagentur.de/DE/Sachgebiete/ElektrizitaetundGas/Unternehmen_Ins

titutionen/ErneuerbareEnergien/Photovoltaik/Strombezug_von_PV-

Anlagen/Strombezug_von_PV-Anlagen.node.html

Bundesnetzagentur. (2017a). Degressions- und Vergütungssätze Oktober bis Dezember 2016.

Retrieved 04 24, 2017, from

https://www.bundesnetzagentur.de/DE/Sachgebiete/ElektrizitaetundGas/Unternehmen_Ins

titutionen/ErneuerbareEnergien/Photovoltaik/ArchivDatenMeldgn/ArchivDatenMeldgn_nod

e.html;jsessionid=A2D03B2A01367559D4DADBF390813548

Bundesnetzagentur. (2017b). Monitoringbericht 2016. Bonn: Bundesnetzagentur.

Bundesregierung Deutschland. (2015, Oktober 24). Verordnung über energiesparenden

Wärmeschutz und energiesparende Anlagentechnik bei gebäuden (Energiesparverordnung -

EnEV). BGBl. I S. 1789. Bundesregierung Deutschland.


Version 1.2


Bundesregierung Deutschland. (2016, 08 29). Verordnung über Allgemeine Bedingungen für den

Netzanschluss und dessen Nutzung für die Elektrizitätsversorgung in Niederspannung.

Niederspannungsvwerordnung - NAV. Bundesregierung Deutschland.

Bundesregierung Deutschland. (2016, August 29). Verordnung über den Zugang zu

Elektrizitätsversorgungsnetzen (Sromnetzzugangsverordnung - StromNZV). Berlin:

Bundesregierung Deutschland.

Byman, K., & IVA. (2016). Electricity production in Sweden. IVA’s Electricity Crossroads project.

Retrieved 11 23, 2017, from https://www.iva.se/globalassets/201604-iva-vagvalel-

elproduktion-english-c.pdf

Carbajo Josa, A. (2007). Los mercados eléctricos y los servicios de ajuste del sistema. (N° 364), 55-62.

Economía Industrial. Retrieved 14 11, 2017, from

http://www.minetad.gob.es/Publicaciones/Publicacionesperiodicas/EconomiaIndustrial/Revi

staEconomiaIndustrial/364/55.pdf

Colthorpe, A. (2017, 07 06). Spanish ‘experimental’ wind farm to be fitted with battery storage by

Acciona. Retrieved from https://www.energy-storage.news/news/spanish-experimental-

wind-farm-to-be-fitted-with-battery-storage-by-acciona

Consentec GmbH. (2014, 02 27). Description of load-frequency control concept and market for

control reserves. Retrieved 09 08, 2017, from

https://www.regelleistung.net/ext/download/marktbeschreibung

Coyne, B. (2017, 06 20). Ofgem confirms deep cuts to Triad payments. the energyst. Retrieved 11 16,

2017, from https://theenergyst.com/ofgem-confirms-deep-cuts-to-triad-payments/

creara Energy Experts. (2016). Development limited by regulation - self-consumption in Spain.

PVFINANCING Workshop 18th October 2016 . CREARA.

Deign, J. (2015, 10 16). Greetechmedia. Retrieved 06 14, 2017, from Spain's new self-consumptoin

law makes batteries impractical for homeowners:

https://www.greentechmedia.com/articles/read/spanish-self-consumption-law-allows-

batteries-at-a-cost

Deutsche ÜNB. (2015a, 09 29). Anforderungen an die Speicherkapazität bei Batterien für die

Primärregelleistung. Retrieved 09 11, 2017, from

https://www.regelleistung.net/ext/static/prl

Deutsche ÜNB. (2015b, 09 29). Anforderungen an die Speicherkapazität bei Batterien für die

Primärregelleistung. Retrieved 09 11, 2017, from

https://www.regelleistung.net/ext/static/prl

EEG. (2016). Gesetz für den Ausbau erneuerbarer Energien (Erneuerbare-Energien-Gesetz - EEG 2017).

EirGrid. (2017). RoCoF Remuneration Mechanism Contract. Retrieved 11 24, 2017, from

http://www.eirgridgroup.com/site-files/library/EirGrid/RoCoF-remuneration-mechanism-

contract-2017-ROI-template-Jun.pdf

ELEXON. (2016, 10 24). Imbalance pricing guidance. Retrieved 09 11, 2017, from

https://www.elexon.co.uk/wp-

content/uploads/2016/10/Imbalance_Pricing_guidance_v11.0.pdf

ELEXON. (2017). Balancing Mechanism Units. Retrieved 09 18, 2017, from

https://www.elexon.co.uk/operations-settlement/balancing-mechanism-units/


Version 1.2


ELEXON. (2017a). Balancing Mechanism Units. Retrieved 11 24, 2017, from

https://www.elexon.co.uk/guidance-note/balancing-mechanism-bm-units/

ELEXON. (2017b). ELEXON. Retrieved 09 11, 2017, from Glossary:

https://www.elexon.co.uk/glossary/

ELEXON Limited. (2011). Code of practice for the metering of import and export active energy via low

voltage circuits for non-half hourly settlement purposes. London: ELEXON.

EnergieAgentur.NRW. (2017). Mieterstrom kurz erklärt - Neue Perspektiven für Vermieter und Mieter.

Düsseldorf: EnergieAgentur.NRW GmbH.

entsoe. (2006, 09 13). Agreement regarding operation of the interconnected Nordic power system.


https://www.entsoe.eu/Documents/Publications/SOC/Nordic/System_Operation_Agreemen

t_English_translation.pdf

entsoe. (2013, 06 28). Supporting Document for the Network Code on Load-Frequency Control and

Reserves. Retrieved 09 05, 2017, from

http://www.acer.europa.eu/Official_documents/Acts_of_the_Agency/Annexes/ENTSO-

E%E2%80%99s%20supporting%20document%20to%20the%20submitted%20Network%20Co

de%20on%20Load-Frequency%20Control%20and%20Reserves.pdf

entsoe. (2015). Continental Europe Operation Handbook. Retrieved 04 06, 2017, from

https://www.entsoe.eu/publications/system-operations-reports/operation-

handbook/Pages/default.aspx

entsoe. (2016). Network Code on Requirements for Grid Connection Applicable to all Generators

(RfG). Retrieved April 12, 2017, from https://www.entsoe.eu/major-projects/network-code-

development/requirements-for-generators/Pages/default.aspx

entsoe. (2016a, 04 14). Network code on requirements for grid connection of generators. Retrieved

09 05, 2017, from http://eur-lex.europa.eu/legal-

content/EN/TXT/PDF/?uri=CELEX:32016R0631&from=EN

entsoe. (2016b, 06 16). Nordic Balancing Philosophy. Retrieved 08 28, 2017, from

http://www.svk.se/contentassets/bc60c82ceaec44c0b9ffbf3ee2126adf/nordic-balancing-

philosophy-160616-final_external.pdf

entsoe. (2016c, 06 23). System Operation Agreement Appendices. Retrieved 08 29, 2017, from

https://www.entsoe.eu/Documents/Publications/SOC/Nordic/System_Operation_Agreemen

t_appendices%28English_2016_update%29.pdf

entsoe. (2016e, 05 04). System Operation Guideline (Final Draft). Retrieved 08 28, 2017, from

https://ec.europa.eu/energy/sites/ener/files/documents/SystemOperationGuideline%20fina

l%28provisional%2904052016.pdf

entsoe. (2017). Balancing and Ancillary Services Markets. Retrieved 03 09, 2017, from

https://www.entsoe.eu/about-entso-e/market/balancing-and-ancillary-services-

markets/Pages/default.aspx

entsoe. (2017, March 17). Network Code on Electricity Balancing (EB). Retrieved April 06, 2017, from

https://www.entsoe.eu/major-projects/network-code-development/electricity-

balancing/Pages/default.aspx


Version 1.2


entsoe. (2017). Production Data. Retrieved 2017, from https://www.entsoe.eu/data/data-

portal/production/Pages/default.aspx

entsoe. (2017a). Balancing and Ancillary Services Markets. Retrieved 03 09, 2017, from

https://www.entsoe.eu/about-entso-e/market/balancing-and-ancillary-services-

markets/Pages/default.aspx

entsoe. (2017a, 03 29). Need for synthetic inertia (SI) for frequency regulation. Retrieved 09 05,

2017, from

file:///home/amotteco/.zotero/zotero/fzjtg1gc.default/zotero/storage/XHJIEW2W/igd-need-

for-synthetic-inertia.html

entsoe. (2017b). Network Code on Electricity Balancing (EB). Retrieved April 06, 2017, from

https://www.entsoe.eu/major-projects/network-code-development/electricity-

balancing/Pages/default.aspx

entsoe. (2017b, 05 24). Supporting Document on Technical Requirements for Frequency

Containment Reserve Provision in the Nordic Synchronous Area. (Draft 2017.5b). Retrieved

31 08, 2017, from https://s3.amazonaws.com/ppt-

download/supportingdocumentontechnicalrequirementsforfrequencycontainmentreservepr

ovisioninthenordicsynchrono-170526093045.pdf?response-content-

disposition=attachment&Signature=FJxrQy2ebfq%2Fd9A3qTsyzFaUGIk%3D&Expires=149985

03

entsoe WGAS. (2017, 03 10). Survey on ancillary services procurement: Balancing market design

2016. Retrieved 07 31, 2017, from

https://www.entsoe.eu/Documents/Publications/Market%20Committee%20publications/W

GAS_Survey_final_10.03.2017.pdf

EnWG. (2017, 03 29). Gesetz über die Elektrizitäts- und Gasversorgung.

EPEX SPOT. (2017a). EPEX SPOT Day-Ahead Auction in UK. Retrieved 11 24, 2017, from

http://www.epexspot.com/en/product-info/auction/uk

EPEX SPOT. (2017b). EPEX SPOT Download Center. Retrieved 11 24, 2017, from

http://www.epexspot.com/en/extras/download-center

eSett. (2017). Handbook. Retrieved 09 15, 2017, from https://www.esett.com/handbook/

EURELECTRIC. (2016). Network Tariffs. Brussels: EURELECTRIC.

European Commission. (2016). Proposal for a Directive of the European Parliament and of the council

amending Directive 2010/31/EU on the energy perfomance of buildings. Brussels: European

Commission.

European Commission. (2016). Quarterly Report on European Electricity Markets, Volume 9, issue 2 &

3. Brussel: Directorate-general for Energy.

European Commission. (2017, 03 27). Market analysis. Retrieved 03 27, 2017, from

https://ec.europa.eu/energy/en/data-analysis/market-analysis

European Commission. (2017). Proposal for a Directive of the European parliament and of he Council

on the promotopn of the use of energy from renewable sources (recast). Brussels: EC.

European Commission. (2017, 03 13). Smart grids and meters. Retrieved 03 13, 2017, from

https://ec.europa.eu/energy/en/topics/markets-and-consumers/smart-grids-and-meters


Version 1.2


European Commission Directorate B. (2015). Study on tariff design for distribution systems. Brussels:

European Commission.

European Power Exchange EPEX SPOT. (2017). The European Power Market - Facts and Figures. Paris:

EPERX SPOT.

Feehally, T., Forsyth, A., & Todd, R. e. (2016). Battery energy storage systems for the electricity grid:

UK research facilities. The 8th IET International Conference on Power Electronics, Machines

and Drives (PEMD). Glasgow: IET Power Electronics, Machines and Drives.

FIZ Karlsruhe. (2016). Stromnetze - Forschungsinitiative der Bundesregierung. Retrieved 04 20, 2017,

from Blackout ohne Folgen: Das Netz mit dezentralen Anlagen starten: http://forschung-

stromnetze.info/projekte/blackout-ohne-folgen-das-netz-mit-dezentralen-anlagen-starten/

Forum Netztechnik/Netzbetrieb im VDE (FNN). (2009). TransmissionCode 2007 Anhang D2 Teil 2

Anforderungen für die Umsetzung des SRL-Poolkonzepts zwischen ÜNB und Anbietern. Berlin:

VDE.

Frontier Economics. (2016, 02). Overview of European Electricity Markets. METIS Technical Note T4.

Retrieved from

https://ec.europa.eu/energy/sites/ener/files/documents/overview_of_european_electricity

_markets.pdf

Frontier Economics. (2017, 03). Transmission Charging Arragements for Embedded Generation.

Retrieved 11 16, 2017, from https://www.ofgem.gov.uk/ofgem-publications/112932

Hirth, L., & Ziegenhagen, I. (2015, 10). Balancing Power and Variable Renewables: Three Links.

Volume 50, Pages 1035-1051. Retrieved 11 23, 2017, from

http://www.sciencedirect.com/science/article/pii/S1364032115004530

Hollinger, R., Diazgranados, L. M., Braam, F., Erge, T., Bopp, G., & Engel, B. (2016). Distributed solar

battery systems providing primary control reserve. Renewable Power Generation 10(1), pp.

63-70.

Hollinger, R., Diazgranados, L., Wittwer, C., & Engel, B. (2016). Optimal Provision of Primary

Frequency Control with Battery Systems by Exploiting All Degrees of Freedom within

Regulation. Energy Procedia, 204-214. Retrieved from

http://linkinghub.elsevier.com/retrieve/pii/S1876610216310724

Hollinger, R., Motte Cortes, A., Erge, T., & Engel, B. (2017, 07 17). Analysis of the Minimum Activation

Period of Batteries in Frequency Containment Reserve. Dresden, Germany: IEEE Explore.

doi:10.1109/EEM.2017.7981904

Hollinger, R., Wille-Haussmann, B., Erge, T., Sönnichsen, J., Stillhahn, T., & Kreifels, N. (2013).

Speicherstudie 2013 (im Auftrag von BSW-Solar). Freiburg: Fraunhofer-Institut für Solare

Energiesysteme ISE.

incite. (n.d.). On Low Inertia Grids. Retrieved 03 24, 2017, from http://www.incite-itn.eu/blog/on-

low-inertia-grids/

International Water Power and Dam Construction. (n.d.). Welcome to the Batcave. International

Water Power and Dam Construction. Retrieved 09 20, 2017, from

http://www.waterpowermagazine.com/features/featurewelcome-to-the-batcave-5868886/

KAV. (2006). Verordnung über Konzessionsabgaben für Strom und Gas

(Konzessionsabgabenverordnung - KAV).


Version 1.2


KfW. (2016). Erneuerbare Energien - Speicher. Retrieved 06 07, 2017, from Strom aus Sonnenenergie

erzeugen und speichern: https://www.kfw.de/inlandsfoerderung/Unternehmen/Energie-

Umwelt/F%C3%B6rderprodukte/Erneuerbare-Energien-%E2%80%93-Speicher-

%28275%29/#2

Krannich Solar. (2016, 01 13). Autoconsumo eléctrico: cómo calcular los cargos fijos por potencia.

Retrieved 10 09, 2017, from http://es.krannich-solar.eu/2016/01/13/autoconsumo-electrico-

cargos-fijos-potencia/

KU Leuven Energy Institute. (2015). The current electricity market design in Europe. Retrieved 09 18,

2017, from https://set.kuleuven.be/ei/images/EI_factsheet8_eng.pdf/

Labastida, R. R. (2017, April 27). NAVIGANT RESEARCH. Retrieved 07 05, 2017, from Can Batteries

Save the UK Solar Market?: https://www.navigantresearch.com/blog/can-batteries-save-the-

uk-solar-market

Li, F., Zhang, Z., Xu, Y., Ahokangas, P., Kopsakangas-Savolainen, M., & Porras, E. (2016, 10 31). P2P-

smartTest - Regulatory, Business, Technological and Social Enablers and Barries of P2P Energy

Transfer. P2P-smartTest. Retrieved 11 20, 2017, from http://www.p2psmartest-

h2020.eu/deliverables

Lian, B., Sims, A., Yu, D., Wang, C., & Dunn, R. (2017, 01). Optimizing LiFePO4 Battery Energy Storage

Systems for Frequency Response in the UK System. IEEE Transactions on Sustainable Energy,

385-394. doi:10.1109/TSTE.2016.2600274

LichtBlick. (2016, 02 04). Stromnetz Hamburg GmbH und Lichtblick machen E-Mobilität attraktiver.


https://www.lichtblick.de/medien/news/2016/02/04/stromnetz-hamburg-gmbh-und-

lichtblick-machen-e-mobilit%C3%A4t-attraktiver

Lindahl, J. (2015). National Survey Report of PV Power Applications in Sweden. Stockholm: Swedish

Energy Agency.

Lundqvist, J. (2014, 03). Our Electricity: What Really Lies Ahead? Mechanisms of tomorrow’s

electricity system and its new regulatory framework – a Nordic perspective. Retrieved 09 20,

2017, from

http://www.svenskenergi.se/Global/Dokument/publikationer/Sv%20Energi_Our%20electrici

ty_What%20really%20lies%20ahead_korr3.pdf

Mainova. (2016). Gewerbekunden Strom - Grund und Ersatzversorgung gültig ab 01.07.2016. Mainz:

Mainova.

Mariscal &Abogados. (2016). Sun Tax on Photovoltaic systems in Spain. Retrieved 06 14, 2017, from

http://www.mariscal-abogados.com/sun-tax-on-photovoltaic-systems-in-spain/

Masson, G., Briano, J. I., & Baez, M. J. (2016). Review and analysis of PV self-consumption policies.

IEA-PVPS T1-28.

Mayr, F., & Adam, S. (2017, 07 17). The German Secondary Control Reserve market: Will recent

regulatory updates finally pave the way for energy storage? Apricum. Retrieved 11 28, 2017,

from https://www.apricum-group.com/german-secondary-control-reserve-market-will-

recent-regulatory-updates-finally-pave-way-energy-storage/

MIBEL Regulatory Council. (2009, 11). Description of the operation of the MIBEL. Retrieved 09 04,

2017, from


Version 1.2


http://www.mibel.com/index.php?mod=documentos&mem=descargar&fichero=documento

s_011_Estudio_MIBEL_EN_v2_2bb9b343.pdf

Ministerio de Industria, Energía y Turismo. (2015, 10 10). Real Decreto 900/2015. BOE-A-2015-10927.

Spain. Retrieved 11 09, 2017, from https://www.boe.es/buscar/pdf/2015/BOE-A-2015-

10927-consolidado.pdf

Ministerio de Industria, Turismo y Comercio. (2011, 05 23). Real Decreto 647/2011. Retrieved 11 16,

2017, from https://www.boe.es/boe/dias/2011/05/23/pdfs/BOE-A-2011-8910.pdf

MITNETZ STROM. (2017, 04). Entgekte Netzanschluss in Niederspannung. Retrieved 06 14, 2017,

from https://www.mitnetz-

strom.de/Stromnetz/Netzanschluss/EntgelteNetzanschlussinNiederspannung

National Grid. (2013a, 02). Constraint Management. Retrieved 11 16, 2017, from

http://www2.nationalgrid.com/WorkArea/DownloadAsset.aspx?id=7033

National Grid. (2013b, 03 10). Mandatory Services: Frequently Asked Questions. Retrieved 09 11,

2017, from http://www2.nationalgrid.com/WorkArea/DownloadAsset.aspx?id=32714

National Grid. (2015a, 06). Black Start Alternative Approaches. Retrieved 15 11, 2017, from

http://www.smarternetworks.org/Project.aspx?ProjectID=1653#project-details

National Grid. (2016a, 03 29). Enhanced Frequency Response - Frequently Asked Questions - Version

5.0. Retrieved 01 19, 2017, from


National Grid. (2016b, 07 08). Enhanced Frequency Response: Invitation to tender for pre-qualified

parties. Retrieved 12 19, 2017, from

https://www.nationalgrid.com/sites/default/files/documents/Enhanced%20Frequency%20R

esponse%20ITT%20v2_2%20clean.pdf

National Grid. (2017a, 03 21). Balancing Code No.3: Frequency Control Process. (Issue 5), Revision 21.



National Grid. (2017b). Black Start. Retrieved 11 15, 2017, from

http://www2.nationalgrid.com/uk/services/balancing-services/system-security/black-start/

National Grid. (2017c, 02). CUSC Section 4: Balancing Services. Retrieved from

http://www2.nationalgrid.com/The-CUSC/The-Connection-and-Use-of-System-Code/Section-

4---Balancing-Services---v1-21/

National Grid. (2017d, 01 20). Demand Turn Up: Frequently Asked Questions. Retrieved 08 30, 2017,

from http://www2.nationalgrid.com/WorkArea/DownloadAsset.aspx?id=8589938599

National Grid. (2017e). Electricity Balance System (BM Replacement). Retrieved 11 24, 2017, from

http://www2.nationalgrid.com/uk/industry-information/electricity-codes/balancing-

framework/electricity-balancing-system/

National Grid. (2017f, 10 25). FFR Market Info Reports - Dec 17. Retrieved 11 13, 2017, from

http://www2.nationalgrid.com/UK/Industry-information/Electricity-transmission-

operational-data/Report-explorer/Services-Reports/#


Version 1.2


National Grid. (2017g, 02 01). Firm Frequency Response tender rules and standard contract terms.



National Grid. (2017h, 02 01). Firm Frequency Response Tender Rules and Standard Contract Terms.



National Grid. (2017i). Frequency Response Services. Retrieved 08 29, 2017, from National Grid UK:

http://www2.nationalgrid.com/UK/Services/Balancing-services/Frequency-response/

National Grid. (2017j, 04 14). Short Term Operating Service: General description of the service.



National Grid. (2017k). Summer Outlook Report. Retrieved 11 16, 2017, from

www2.nationalgrid.com/WorkArea/DownloadAsset.aspx?id=8589939683

National Grid. (2017l, 06). System Needs and Product Strategy. Retrieved 09 18, 2017, from


National Grid. (2017m, 07 19). Testing guidance for providers of firm frequency response balancing

service. Retrieved 11 20, 2017, from


National Grid. (2017n, 11). Testing guidance for providers of firm frequency response balancing

service. Retrieved 12 19, 2017, from

https://www.nationalgrid.com/sites/default/files/documents/FFR%20Testing%20Guidance%

20verD11%20Final.pdf

National Grid. (2017o). The Connection and Use of System Code. Retrieved 11 17, 2017, from

http://www2.nationalgrid.com/uk/industry-information/electricity-codes/cusc/the-cusc/

National Grid. (2017p). Triad Data. Retrieved 11 16, 2017, from

http://www2.nationalgrid.com/UK/Industry-information/System-charges/Electricity-

transmission/Transmission-Network-Use-of-System-Charges/Transmission-Charges-Triad-

Data/

nationalgrid. (2017). Short Term Operating Reserve. Retrieved 04 06, 2017, from

http://www2.nationalgrid.com/uk/services/balancing-services/reserve-services/short-term-

operating-reserve/

NeMoG. (2017). Entwurf eines Gesetzes zur Modernisierung der Netzentgeltstruktur

(Netzentgeltmodernisierungsgesetz).

Nord Pool. (2017). Bidding Areas. Retrieved 31 08, 2017, from Nord Pool:

http://www.nordpoolspot.com/the-power-market/Bidding-areas/

Nord Pool. (2017a). Nord Pool Rules and Regulations. Retrieved 11 24, 2017, from

http://www.nordpoolspot.com/TAS/Rules-and-regulations/

Nord Pool. (2017b, 07 03). Product specification: Nordic, Baltic and German market areas. Retrieved

08 31, 2017, from http://www.nordpoolspot.com/globalassets/download-center/rules-and-

regulations/product-specifications-nordic-baltic-and-german-market_valid-from-3-july-

2017.pdf


Version 1.2


NordREG. (2016). Status report on regulatroy aspects of demand side flexibility. Retrieved 11 24,

2017, from http://www.nordicenergyregulators.org/wp-content/uploads/2016/12/NordREG-

Status-report-on-regulatory-aspects-of-demand-side-flexibility.pdf

Offenberg, P. (2016). European Electricity Market Integration. International Seminar "Integration and

Electrical Security in Latin America". Rio de Janeiro.

Ofgem. (2016, 08 03). Wholesale Energy Markets in 2016. Retrieved 08 31, 2017, from

https://www.ofgem.gov.uk/system/files/docs/2016/08/wholesale_energy_markets_in_2016

.pdf

Ofgem. (2017). Electricity trading volumes and churn ratio by month and platform (GB). Retrieved 08

31, 2017, from Ofgem: https://www.ofgem.gov.uk/data-portal/electricity-trading-volumes-

and-churn-ratio-month-and-platform-gb

ofgem. (2017). Onsite generation and metering. Retrieved 07 05, 2017, from

https://www.ofgem.gov.uk/consumers/household-gas-and-electricity-guide/understand-

smart-and-other-energy-meters/onsite-generation-and-metering

Parliament of Great Britain. (2002). The Electricity Safety, Quality and Continuity Regulations. The

Stationery Office Limited. Retrieved 09 15, 2017, from

http://www.legislation.gov.uk/uksi/2002/2665/pdfs/uksi_20022665_en.pdf

Pause, F., & Wizinger, S. (2016, 08 31). BestRES - Technical, legal and regulatory barriers for current

business models. Retrieved 11 20, 2017, from http://bestres.eu/wp-

content/uploads/2016/12/D2.3.pdf

Periodistas en espanol.com. (2017, 05 22). Europa estudia ilegalizar el impuesto al sol vigente an

Espana. Retrieved 06 14, 2017, from http://periodistas-es.com/europa-estudia-ilegalizar-

impuesto-al-sol-vigente-espana-86221

Ponton. (2017). The Enerchain Project. Retrieved 11 20, 2017, from

https://enerchain.ponton.de/index.php

Red Eléctrica de España. (1998, 08 18). Servicio complementario de regulación primaria. Boletín

Oficial del Estado(197), pp. 28158-28183. Retrieved 08 25, 2017, from

http://www.ree.es/sites/default/files/01_ACTIVIDADES/Documentos/ProcedimientosOperac

ion/PO_resol_30jul1998_b.pdf

Red Eléctrica de España. (2000, 03 10). P.O. 7.4 Servicio complementario de control de tensión de la

red de transporte. Retrieved 14 11, 2017, from


ion/PO_resol_10mar2000_correc.pdf

Red Eléctrica de España. (2006, 07 21). Establecimiento de la reserva para la regulación frecuencia-

potencia. Boletín Oficial del Estado(173), pp. 27473-27474. Retrieved 08 25, 2017, from


ion/RES_PO_1.5.pdf

Red Eléctrica de España. (2013). Proyecto Almacena. Retrieved from

http://www.ree.es/es/red21/idi/proyectos-idi/proyecto-almacena

Red Eléctrica de España. (2014, 12 15). Importancia del Equipo Generador Hidroeléctrico en la

Operación del Sistema Eléctrico. Retrieved 14 11, 2017, from

http://www.chebro.es:81/Plan%20Hidrologico%20Ebro%202015-


Version 1.2


2021/2%20Revisi%C3%B3n%202015-

21%20del%20Plan%20Hidrol%C3%B3gico%20del%20Ebro/2.1%20Informe%20de%20propues

tas,%20observaciones%20y%20sugerencias/Documentos%20originales/006-

%20RED%20ELECTRICA%20ESPA

Red Eléctrica de España. (2015a, 12 19). Secondary and Tertiary Regulation. Boletín Oficial del

Estado(303), pp. 19723-19944. Retrieved 07 24, 2017, from


ion/RES_VAR_20151218_Participacion_en_servicios_de_ajuste_y_aprobacion_POs.pdf

Red Eléctrica de España. (2015b, 12 19). P.O. 3.3 Gestión de desvíos. BOE-A-2015-13875. Spain.



ion/RES_VAR_20151218_Participacion_en_servicios_de_ajuste_y_aprobacion_POs.pdf

Red Eléctrica de España. (2015c, 05). System adjustment services for Spain's peninsular electrical

system. Spain. Retrieved 08 24, 2017, from

https://api.esios.ree.es/documents/80/download?locale=es

Red Eléctrica de España. (2017). ESIOS: Sistema de información del operador del sistema. Retrieved

11 24, 2017, from www.esios.ree.es

regelleistung.net. (2017a). IT requirements. Retrieved 11 24, 2017, from

https://www.regelleistung.net/ext/static/srl/it?lang=en

regelleistung.net. (2017b). Method for determining the reBAP. Retrieved 24 11, 2017, from

https://www.regelleistung.net/ext/static/rebap

SMA. (2012, 02 06). Wie funktioniert Eigenverbrauch von Solarstrom? Retrieved 05 08, 2017, from

http://www.sma-sunny.com/wie-funktioniert-eigenverbrauch-von-solarstrom/

Smart Energy Demand Coalition - SEDC. (2017, 04 06). Explicit Demand Response in Europe: Mapping

the markets 2017. Brussels, Belgium. Retrieved 11 29, 2017, from

http://www.smartenergydemand.eu/wp-content/uploads/2017/04/SEDC-Explicit-Demand-

Response-in-Europe-Mapping-the-Markets-2017.pdf

Solar Trade Association. (2016). National Policy Advisory Pape - Towards a long-term and sustainable

framework for solar in the UK. London: Solar Trade Association.

Solar Trade Association. (2017, 03 07). Chancellor urged to drop the solar tax hike. Retrieved 07 05,

2017, from http://www.solar-trade.org.uk/chancellor-urged-drop-solar-tax-hike/

Soyck, F., Schilling, F., Schmidt, M., & Engel, B. (2015). Real time calculation of virtual meter points

for simultaneous multiple use of PV storage systems; Die Energiewende - Blueprints for the

new energy ageBlueprints. International ETG Congress 2015, (pp. 1-7).

Statnett, Fingrid, Energinet.dk, Svenska Kraftnät. (2016a, 12 01). Nordic System Operation Forum.


https://www.entsoe.eu/Documents/Publications/SOC/Nordic/System_Operation_Forum_01

1216_Stockholm_presentations.pdf

Steel, W. (2016, 10 26). Renewable Energy World. Retrieved 07 03, 2017, from Sweden Set to Launch

Residentiual Energy Storage Scheme:

http://www.renewableenergyworld.com/articles/2016/10/sweden-set-to-launch-residential-

energy-storage-scheme.html


Version 1.2


Stöhr, M. (2015). Second life use of electric vehicle batteries in buildings and districts - the H2020-

ELSA project. Smart Grid Plus ERA-Net Scoping Workshop. Malmö.

Stoker, L. (2017, 04 07). Inflexible generators face summer curtailment as National Grid prepares for

soaring solar. Retrieved 11 06, 2017, from

https://www.cleanenergynews.co.uk/news/solar/inflexible-generators-face-summer-

curtailment-as-national-grid-prepares-for

stoRE Project. (n.d.). Análisis del marco regulatorio y de Mercado en España. Retrieved 11 14, 2017,

from http://backend.store-project.eu/uploads/docs/presentations-in-national-

workshops/es-regulacion-spain.pdf

StromNEV. (2016). Verordnung über die Entgelte für den Zugang zu Elektrizitätsversorgungsnetzen

(Stromnetzentgeltverordnung - StromNEV).

Svenska Kraftnät. (2015a, 02 01). Balance Responsibility Agreement for electricity between the

Svenska Kraftnät Public Utility and a Balance Responsible Party. Retrieved 08 28, 2017, from

http://www.svk.se/siteassets/aktorsportalen/elmarknad/balansansvar/dokument/brp-

agreement-20150201.pdf

Svenska Kraftnät. (2015b, 12 17). Regler för upphandling och rapportering av FCR-N och FCR-D.

Retrieved from

http://www.svk.se/siteassets/aktorsportalen/elmarknad/balansansvar/dokument/balansans

varsavtal/regler-for-upphandling-och-rapportering-av-fcr.pdf

Svenska Kraftnät. (2016a). Avtal om Balansansvar för el mellan Affärsverket svenska kraftnät

("Svenska Kraftnät") och. Retrieved from

http://www.svk.se/siteassets/aktorsportalen/elmarknad/balansansvar/dokument/balansans

varsavtal/balansansvarsavtal-2016.pdf

Svenska Kraftnät, Statnett. (2017, 06). The Nordic Balancing Concept. Version 1. Retrieved 28 08,

2017, from

http://www.statnett.no/Global/Dokumenter/Kraftsystemet/Markedsinformasjon/Landssentr

alen/The%20Nordic%20Balancing%20Concept.pdf

Svenska Kraftnät, Stattnet, Fingrid, Energie.dk. (2016b, 08 15). Challenges and Opportunities for the

Nordic Power System. Retrieved 09 20, 2017, from

http://www.statnett.no/Global/Dokumenter/Challenges%20and%20opportunities_Report.p

df

Thalman, E., & Wehrmann, B. (2017). What Germany households pay for power (Factsheet). Berlin:

Clean Energy Wire.

the energyst. (2016, 09 23). Reducing DUoS Red Band charges. Retrieved 11 16, 2017, from

https://theenergyst.com/reducing-duos-red-band-charges/

Tjaden, T., & Weniger, J. Q. (2016). Wirkungsgrade bei elektrischen Solarspeichersystemen. ISFH

Kolloquium. Emmerthal: ISFH.

Underhill, P., Matthew, R., Cheung, R., & Sims, A. (2016, 02 06). Enhanced Frequency Response.

Birmingham. Retrieved 01 25, 2017, from


VDE FNN. (2017). Allgemeines und Übersicht zu Technischen Anschlussregeln. Retrieved 04 19, 2017,

from https://www.vde.com/de/fnn/themen/tar/uebersicht


Version 1.2


VDN. (2007). Kalkulationsleitfaden §18 StromNEV. Berlin: VDN.

Verband der Netzbetreiber VDN e.V. beim VDEW. (2003). Transmission Code 2003. Anhang D1:

Unterlagen zur Präqualifikation für die Erbringung von Primärregellestung für die ÜNB (Stand

August 2003). Retrieved 03 21, 2017, from

https://www.vde.com/resource/blob/937784/46070ff6f906891b65d537ae8a648c5b/transm

issioncode-2007--netz--und-systemregeln-der-deutschen-uebertragungsnetzbetreiber-

anhang-d1-data.pdf

von Appen, J., Braun, M., Zinßer, B., & Stellbogen, D. (2012). Leistungsbegrenzung bei PV-Anlagen -

Anpassung der Modellierungsmethoden und Vergleich verschiedener Standorte. 27.

Symposium "Photovoltaische Solarenergie". Bad Staffelstein: OTTI.

Wallnerström, C., Grahn, E., Wigenborg, G., Wether Öhling, L., Bobadilla Robles, H., Alvehag, K., &

Johansson, T. (2016, 08). The Regulation of Electricity Network Tariffs in Sweden from 2016.

Swedish Association for Energy Economics Conference 2016. Retrieved 11 17, 2017, from

https://www.researchgate.net/publication/308116249_The_Regulation_of_Electricity_Netw

ork_Tariffs_in_Sweden_from_2016

Wigenborg, G., Werther Öhling, L., J Wallneström, C., Grahn, E., Alvehan, K., Ström, L., & Johansson,

T. (2016, 07 28). Incentive scheme for efficient utilization of electricity network in Sweden.

2016 13th International Conference on the European Energy Market (EEM). IEEE.

doi:10.1109/EEM.2016.7521188

Will, H., & Zuber, F. (2016). Geschäftsmodelle mit PV-Mieterstrom. München, Berlin: BSW-Solar.

Wille-Haussmann, B., Hollinger, R., & Freiberger, D. (2017). own recherche. Freiburg: Fraunhofer ISE.

Zahng, C., Wu, J., Long, C., & Cheng, M. (2016, 05). Review of Existing Peer-to-Peer Energy Trading

Projects. Energy Procedia, Volume 105, Pages 2563-2568.

Zeh, A., Müller, M., Naumann, M., Hesse, H. C., & Witzmann, R. (2016, Spetember 13). Fundamentals

of Using Battery Energy Storage Systems to provide Primary Control Reserves in Germany.

Batteries, 2(29).

Zucker, A. (2016, July 4). Energy self-consumption and regulation schemes. Retrieved 04 20, 2017,

from https://ec.europa.eu/jrc/sites/jrcsh/files/20160704-05-smartenergyregions-zucker.pdf


Version 1.2


Annexes Annex 1: Medians (white horizontal bars) and distribution of FCR prices data and selected values (as black dots) utilized to calculate revenues for FCR provision. Source: (Fraunhofer ISE, 2017)

Annex 2: Potential profit calculation for 2015 for FCR products in selected countries. Source: (Fraunhofer ISE, 2017)

Note: Germany (PCR), Spain (PR), Sweden (FCR-N and FCR-D), UK (FFR PSH, EFR Narrow and EFR Wide).


Version 1.2


Annex 3: Comparison of cumulated response energy flows for all products with and without the application of an operation strategy exploiting available regulatory degrees of freedom. Source: (Fraunhofer ISE, 2017).

Deliverable 5 - NETfficientnetfficient-project.eu/wp-content/uploads/2018/01/D5.14... ·...

Documents

Transcript of Deliverable 5 - NETfficientnetfficient-project.eu/wp-content/uploads/2018/01/D5.14... ·...