GIZ – Thermal Power Plant Flexibility Improvements in...

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GIZ – Thermal Power Plant Flexibility Improvements in Chile

14 Mar 2017

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Prepared for

GIZ

In the framework of

WBS SPR04875

Written by

Arnaud Lambert / Thomas Grandry / Sebastián Michels / Xavier Degive / Julio González

This document is electronically signed.

Verifier

Demaude Olivier

Approver

Junge Cristian

Approver

Stockmans Pieter-Jan

Este estudio fue realizado para GIZ en el marco del proyecto “Fomento de la energía solar en Chile” por encargo del Ministerio de Medio Ambiente de Alemania y el Ministerio de Energía de

Chile como contraparte oficial.


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Laborelec Chile is an International Center of Excellence supported by CORFO.

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Version number Date Description and modification history

LBE04118739 - 3.0 14 Mar 2017 New report.

Abstract

Chilean electricity market has experienced an accelerated increase in the penetration of

variable renewable energies and they are expected to represent a significant part of the

energy mix in the coming years (~40% by 2030). Thermal plants will keep a key role in the

future to provide flexibility to the grid in order to integrate this new intermittent energy supply.

In this context, the Deutsche Gesellschaft für Internationale Zusammenarbeit (GIZ) GmbH

and the Chilean Ministry of Energy, jointly requested ENGIE Lab Laborelec support to define

standards in order to optimize the flexibility of the current and future fleet in Chile.

This report describes the organization of the power system in European countries and

summarizes typical benchmark performances. From those examples, a comparison is made

with the current situation in Chile and a set of recommendations is ultimately provided to

feed the discussion for the new regulatory framework in Chile.

Executive summary

The successful integration of intermittent renewable energy sources in the Chilean Energy

mix will require an increased degree of flexibility of the power system that will challenge the

operation of the conventional thermal fleet. In this scenario, the regulatory framework is a

key influencing factor to realize the objectives defined by the Chilean authority.

The evolution of the European thermal plants, initially designed for base load, to flexible

units was mainly driven by a very competitive market in a context of overcapacity. It

demonstrates that significant improvements can be realized when enough incentives exist.

This report begins with a review of the market mechanisms put in place by the authorities of

two European countries, namely Italy and Belgium, which fostered the improvement of the

operational parameters such as turn down, ramp rates and start up times to achieve more

system flexibility (Chapter 2). European context is taken into account. The organization of

the ancillary services in Italy and Belgium, which adopt different approaches on some topics,

can clearly be used as examples in Chile to develop a new regulatory framework while taking

into consideration the specificities of the country and the conceptual choices made by the

authorities.

The grid in Italy is somehow comparable to the Chilean one, with an antenna structure for

energy distribution, low exchange capacity with the neighbouring countries as well as limited

transport capacity from North to South within the grid. High percentage of conventional

thermal power plants (Gas, Coal) provides the energy. The share of renewable energy is

continuously increasing.


Belgium, on the other hand, has a highly interconnected network, within the country as well

as with the neighbouring countries. A high share of non-flexible nuclear power provides the

energy, as well as a mix of Gas assets and one large energy storage (pumped hydro) system

of around 1GW. In this context CCGTs are requested to stop and start very frequently.

Beyond the specific attributes of Italy and Belgium markets, both ancillary services markets

are characterized by the clear definition of products and technical requirements plants

should meet in order to provide the services.

Chapter 2 also provides the technical definitions of the relevant concepts commonly used to

characterize the ancillary services, the technical operation of the plants and the electricity

market, which may be used as a reference.

The market review is followed by the analysis of the impact of power system requirements

on operational parameters of thermal plants, the technical/environmental limitations for

flexible operation and an international benchmark of operational parameters (Chapter 3).

To participate in the flexibility market, power plants have to comply with specific technical

requirements for the provision of the services, which at the plant level are met by challenging

operational parameters. This link between system requirements and operational parameters

is explained. It is also shown how in a highly competitive environment, plants were given

financial incentives to improve their parameters over the years in order to catch market

opportunities and remain profitable.

To characterize the limitations for the improvement of the operational parameters, three

categories were defined: Rankine Cycles, Combined Cycles (CCGTs) and Open Cycles

(OCGTs). For each category, the typical hurdles to improve the operational parameters that

are most important for the provision of ancillary services (focus on frequency control) are

explained. For instance ramp rate, Pmax increase and Pmin reduction among others are

analysed.

Same categories were considered in a performance benchmark, which includes more than

45 European thermal assets from 11 different countries. Values of relevant flexibility

parameters such as Pmin, Pmax, relative turndown, ramp rate, start up times, minimum up and

down time are provided in percentile ranges, to illustrate the average performance and

spread for each power plant category. The benchmark concludes the review of the

international best practices.

Chapter 4 describes the current situation in Chile, providing an overview of the electric

systems, market organization, regulatory framework and emission limits. This chapter is

followed by the gap analysis, where gaps are detected between the reference cases taken

in EU and the current situation in Chile.

First, gaps in the definition of operational parameters as defined in the NTSyCS with respect

to the definition proposed in the international review are detailed. The following was

identified:

Minimum power output definition: the incompatibility between DS N° 13/2011 and

the NTSyCS is highlighted.

Start-up time definition: the necessity of defining more types of start-up times is

pointed out and the concept of start-up curve is presented as a possibility.

Furthermore, the influence of the preparation time on the start-up time is explained.


Ramp rate, minimum uptime and downtime are not defined in the NTSyCS but are

declared by power plants.

The second section of the analysis describes the gaps related to grid infrastructure and

energy and ancillary services markets. The main differences between Italy, Belgium and

Chile are summarized in comparison tables. Significant differences exist in the organization

of the power system between Europe and Chile, a main one being the central dispatching

of the plants in Chile. Regarding ancillary services, points of interest for Chile are listed

hereunder:

No bid market for ancillary services and no specific capacity payment: the selection

is made by the central authority based on a techno-economical choice

PFC approach is different in SIC and SING: like Belgium for SIC (selected units)

and like Italy for SING (de-rating on all thermal units)

No on-line testing of the PFC

Requirements are imposed at individual plants level (as for Italy)

Tertiary reserve is part of the central dispatching management (not a specific

“requirement”)

Next, gaps in the operational parameters are analysed in detail. For each technology the

start-up time, ramp rate, relative turndown, minimum uptime and minimum downtime of the

thermal assets in Chile are compared with the European thermal assets. Additional

international reference values from the literature are also taken into account. The report

points out several technical under performances of the current Chilean fleet which could be

improved. Main findings are described below:

Rankine cycles: In terms of ramp rate and turndown, the fleet of Rankine cycles in

Chile were found to be as flexible as the references in Europe (excluding USC

units), but much less flexible than some other international references.

Combined cycles: In Chile, the fleet of CCGTs were found to be less flexible in

comparison to the fleet of CCGTs taken in Europe, especially in terms of ramp

rates and turndown. The same observation is made with a comparison with

international references.

Open cycles: In Chile, the fleet of OCGTs are not found to be flexible in comparison

to the fleet of OCGTs in Europe, in particular in term of start-up time.

Finally, gaps found regarding the emission limit values point out that CO and NOx emission

limits play a key role on the definition on the Pmax and Pmin of OCGTs and CCGTs. While

NOx emission limits in Chile are found to be equivalent to the value of the IE-D (European

Industrial Emissions Directive) and to the P50 of the benchmark, there is no limit for CO

emissions defined. Additionally, in Chile the emission limits apply at part-loads, making the

regulation sometimes more stringent than in Europe. In Europe, the IE-D set minimum

emission limits for an operation above 70% of the load. The emission limit for an operation

below 70% are set by the local authorities, which can introduce more flexibility in the

emission limit for part load operation.

The report concludes with a series of proposals that Engie Lab Laborelec sees as

opportunities to support future grid flexibility, such as:


Measures to increase the transparency in the grid balancing needs, by further

packaging the requirements for ancillary services in clear products

Measures to improve the verification of the real plant performances, e.g. by

online remote testing for PFC

Incentives for the supply of ancillary services, in order to push the plants to

improve their flexibility performances, e.g. with specific bid mechanism

A clear framework which assures that new plants are in line with best practices

All suggestions are summarized in the roadmap at the end of the report. The proposals are

based on a high level evaluation aiming at feeding the discussion on the new regulatory

framework for thermal power plants in Chile. Difference between the following scenarios is

made:

Measures which could be taken with the current organization of the ancillary

services (no market)

Measures applicable if an ancillary service market is put in place

Measures applicable if an energy market (decentralized dispatching) is put in

place


Contents

Abbreviations ................................................................................................................................... 11

1. Introduction and context .................................................................................................... 14

2. Study Cases and Analysis of International Best Practices................................................. 16 2.1. Technical Definitions .............................................................................................. 16

Ancillary Services ........................................................................................ 16 Operational Parameters (*) ......................................................................... 19 Electricity market ......................................................................................... 26

2.2. European context [11] ............................................................................................ 27 Evolution of the electricity market liberalisation in EU [12] .......................... 27 Overview of EU energy market ................................................................... 29

2.2.2.1. Grid management .................................................................................. 29 2.2.2.2. Electricity markets .................................................................................. 30

ENTSO-E technical requirements [3] .......................................................... 32 2.2.3.1. Ancillary services ................................................................................... 32 2.2.3.2. Other requirements ................................................................................ 34

Emissions .................................................................................................... 36 2.3. Description of the Italian Flexibility Market ............................................................. 37

Overview of the Italian market [15] .............................................................. 37 Market organization [16] .............................................................................. 38

2.3.2.1. Day ahead market .................................................................................. 39 2.3.2.2. Intraday market ...................................................................................... 40 2.3.2.3. Ancillary Services Market ....................................................................... 41 2.3.2.4. Forward market MTE, IDEX and CDE platform ...................................... 41 2.3.2.5. Capacity payments for planned shortage (“essential plants”) ................ 42

Extra considerations about the Italian system ............................................. 42 Detailed information about the Ancillary Services ....................................... 42

2.3.4.1. Primary Frequency Control – PFC (R1) ................................................. 43 2.3.4.2. Secondary Frequency Control (R2)........................................................ 44 2.3.4.3. Tertiary Frequency Control (R3) ............................................................ 45 2.3.4.4. Black start .............................................................................................. 46 2.3.4.5. Reactive power supply ........................................................................... 47

Energy imbalance penalties ........................................................................ 47 Summary table and key highlights .............................................................. 48 Market evolution [23] ................................................................................... 48

2.4. Description of the Belgian Flexibility Market ........................................................... 49 Overview of the Belgian Market [24] ........................................................... 49 Market Organization [25] ............................................................................. 49

2.4.2.1. Day ahead market .................................................................................. 50 2.4.2.2. Intraday market ...................................................................................... 51


2.4.2.3. Ancillary service market ......................................................................... 51 2.4.2.4. Forward market ...................................................................................... 51 2.4.2.5. Capacity payment for planned shortage (“strategic reserve”) ................ 51

Extra considerations about the Belgian system........................................... 52 Detailed information about the Ancillary Services ....................................... 52 Imbalance penalties .................................................................................... 56 Summary table and key highlights .............................................................. 57 Market evolution .......................................................................................... 57

2.5. Comparison tables ................................................................................................. 58

3. Impact of flexibility on thermal plants and technical limitations .......................................... 59 3.1. Conventional Power Plant Categories .................................................................... 59 3.2. Impacts of the power system requirements on the technical parameters of thermal

plants ...................................................................................................................... 60 3.3. Technical limitations for each category (including emissions) ................................ 66

Rankine cycles ............................................................................................ 66 CCGTs ........................................................................................................ 69 OCGTs ........................................................................................................ 75 Emissions .................................................................................................... 76

3.4. Performance benchmark for each category............................................................ 77 3.4.1.1. Rankine cycles ....................................................................................... 78 3.4.1.2. CCGTs ................................................................................................... 79 3.4.1.3. OCGTs ................................................................................................... 80

4. Analysis of the current situation in Chile ............................................................................ 81 4.1. Overview of Chilean Electric Systems .................................................................... 81 4.2. Market Organization ............................................................................................... 83

4.2.1.1. Spot Market ............................................................................................ 83 4.2.1.2. Financial Market ..................................................................................... 84

4.3. Regulatory framework for Ancillary Services .......................................................... 85 4.3.1.1. Primary Frequency Control (PFC) .......................................................... 86 4.3.1.2. Secondary Frequency Control (PFC) ..................................................... 87 4.3.1.3. Voltage Control ...................................................................................... 87 4.3.1.4. Service Recovery Plans (SRP) .............................................................. 88 4.3.1.5. Load Shedding Schemes ....................................................................... 88 4.3.1.6. Evolution mechanisms in the regulatory framework for ancillary services

88 4.4. Emission limits in Chile for thermal power plants ................................................... 89

Evolution mechanisms related to emissions limits in Chile ......................... 90

5. Gap analysis ...................................................................................................................... 92 5.1. Gaps in Definitions for Operational Parameters ..................................................... 92

Minimum power output (Pmin) ...................................................................... 92 Start-up times .............................................................................................. 92 Ramp rate, minimum uptime and downtime ................................................ 94

5.2. Gaps in the grid organization, energy and ancillary markets .................................. 94 Grid infrastructure ....................................................................................... 94 Energy market organization ........................................................................ 96 Ancillary services ........................................................................................ 97

5.3. Gaps in the operational parameters of thermal power plants ................................. 99 Rankine cycles .......................................................................................... 100


5.3.1.1. Relative turndown ................................................................................ 100 5.3.1.2. Ramp rate ............................................................................................ 101 5.3.1.3. Cold start-up time ................................................................................. 102

Minimum uptime ........................................................................................ 103 Minimum downtime ................................................................................... 104 CCGTs ...................................................................................................... 104

5.3.4.1. Relative turndown ................................................................................ 105 5.3.4.2. Ramp rate ............................................................................................ 106 5.3.4.3. Cold start-up time ................................................................................. 107

Minimum uptime ........................................................................................ 108 Minimum downtime ................................................................................... 109 OCGTs ...................................................................................................... 110

5.3.7.1. Relative turndown ................................................................................ 110 5.3.7.2. Ramp rate ............................................................................................ 111 5.3.7.3. Start-up time ........................................................................................ 112 5.3.7.4. Minimum uptime ................................................................................... 113 5.3.7.5. Minimum downtime .............................................................................. 113

5.4. Gaps in emission regulations ............................................................................... 114 Limit values ............................................................................................... 114 Application ................................................................................................ 115

6. Proposed Roadmap for the future ................................................................................... 116 6.1. Measures which could be taken with the current organization of the ancillary

services (no market) ............................................................................................. 116 6.2. Measures applicable if an ancillary service market is put in place........................ 120 6.3. Measures applicable if an energy market (decentralized dispatching) is put in place

............................................................................................................................. 122

Bibliography.......................................................................................................... 124

Overview of Chilean Thermal Fleet ...................................................................... 127

List of figures ........................................................................................................ 131


Abbreviations

ACE Area Control Error

AEEGSI Italian Regulatory Authority for Electricity, Gas and Water

AGC Automatic Generation Control

ARP Access Responsible Parties

AS Ancillary Services

BAT Best Available Techniques

Belpex Belgian power exchange

BOP Balance Of Plant

BREF Best available techniques Reference document

CC, CCGT Combined-Cycle, Combined-Cycle Gas Turbine

CDE Consegna derivati energia - Market for Electricity Derivatives operated by the Borsa

Italiana

CDEC Centro de Despacho Económico de Carga - Load Dispatch Center (Chile)

CE Continental Europe

CFPP Coal-Fired Power Plant [1]

CHP Combined Heat and Power (aka. cogeneration)

CNE Comision Nacional de Energia – Chilean National Commission of Energy

CO Carbon Monoxide

DLN Dry Low NOx

DS Decreto Supremo - Supreme Decree

DSM Demand Side Management

DSO Distribution System Operator

ELIA Belgian TSO

ELL ENGIE Lab Laborelec

ELV Emission Limit Value

ENTSO-E European Network of Transmission System Operators

ESP Electrostatic Precipitator

ERNC Energías Renovables No Convencionales – Renewable Energy Sources (w/o large

hydro)

FF Fabric Filter


FGT Flue Gas Treatment

GIZ Gesellschaft für Internationale Zusammenarbeit - German Corporation for

International Cooperation

GME Gestore dei Mercati Energetici – Load Dispatch Center (Italy)

GT Gas Turbine

HRSG Heat Recovery Steam Generator

ICE InterContinental Exchange

IDEX Italian Derivatives Energy Exchange

IE-D Industrial Emission Directive

IEM Infraestructura Energética Mejillones

ISO Independent System Operator, or International Organization for Standardization

when referring to RSC

LCP-D Large Combustion Plant Directive

LTSA Long-Term Service Agreement

MB Mercato del Bilanciamento - Real-time Balancing Market (Italy)

MCR Maximum Continuous Rating

MGP Mercato del Giorno Prima - Day-Ahead Market (Italy)

MI Mercato Infragiornaliero - Intraday Market (Italy)

MPE Mercato elettrico a pronti - Spot Electricity Market (Italy)

MRC Multi Regional Coupling

MSD Mercato dei Servizi di Dispacciamento - Ancillary Services Market (Italy)

MTE Mercato a Termine - Forward Electricity Market (Italy)

NOx Mono-nitrogen oxides

NRA National Regulatory Authority

NTSyCS Norma Técnica de Seguridad y Calidad del Servicio – Chilean Grid Code

OC, OCGT Open-Cycle, Open-Cycle Gas Turbine

OEM Original Equipment Manufacturer

P10, P50, P90 10th percentile, 50th percentile, 90th percentile

PC Pulverized Coal

PFC Primary Frequency Control

PM, PM10,

PM2.5

Particulate Matter, Particulate Matter 10 micrometres or less in diameter, Particulate

Matter 2.5 micrometres or less in diameter

Pmax Maximum net active power


Pmin, Pmin_env,

Pmin_tech, Pmin

exceptional

Minimum net active power, Environmental Pmin, Technical Pmin, Exceptional Pmin

R1 Equivalent to “Primary Frequency Control”

R2 Equivalent to “Secondary Frequency Control”

R3 Equivalent to “Tertiary Frequency Control”

RC Rankine Cycle

RES Renewable Energy Sources

RM Region Metropolitana – Santiago Metropolitan Region

RSC Reference Site Conditions

RES Renewable Energy Sources (usually non dispatchable RES in this report)

RSC Reference Site Conditions

SADI Sistema Argentino de Interconexión – Interconnected System of Argentina

SCR Selective Catalyst Reduction

SFC Secondary Frequency Control

SIC Sistema Interconectado Central - Central Interconnected System

SIN Sistema Interconectado Nacional – National Interconnected System

SING Sistema Interconectado del Norte Grande - Interconnected System of Norte Grande

SRP Service Recovery Plan

TERNA Italian TSO

TFC Tertiary Frequency Control

TSO Transmission System Operator

USC Ultra-Super Critical

VSD, or VFD Variable Speed Drive, or Variable Frequency Drive


1. Introduction and context

In the latest years, Chilean electricity market has experienced an accelerated increase in

the penetration of variable renewable energies and most challenging scenarios foresee that

their participation in energy production might scale up to approximately 40% in 2029 [mesa

ERNC] and even 60% towards 2050 [GIZ]. Given the fact that these energy sources are

variable and difficult to predict, the successful integration into the power system requires

certain degree of flexibility that challenges the operation of conventional thermal generation

fleet.

In this context, The Deutsche Gesellschaft für Internationale Zusammenarbeit (GIZ) GmbH

and the Chilean Ministry of Energy, jointly request support for defining standards for the

design, operation and maintenance of thermal power plants, so that the actual and the future

fleet in the Chilean electricity market is able to operate in a more flexible way.

The purpose of the study is to provide recommendations to the Chilean Regulatory Authority

CNE (Comisión Nacional de Energía) for establishing a regulatory framework for thermal

power plants, which fosters the increase in the flexibility of the power system.

The study is divided in three steps:

Fist, a review of the international best practice is performed comprising two countries: Italy

and Belgium, which were selected based on their geographic, grid and market

characteristics. General European context is also taken into account.

Italy, to some extent, has a comparable grid like in Chile, with an antenna structure for

energy distribution. Low interchange capacity with the neighbouring countries as well as

limited transport capacity from North to South within the grid. High percentage of traditional

power plants (gas, coal) provide the energy. The weight of renewable energy is continuously

increasing.

Belgium, on the other hand, has a highly interlinked network, within the country as with the

neighbouring countries. A high percentage of non-flexible nuclear power generation

provides the energy, as well as a mix of gas assets and one large energy storage (hydro)

system of around 1GW. In this context CCGTs are requested to stop and start very

frequently.

The review focuses on four topics:

Mechanisms employed by the TSOs and relevant authorities to foster system

flexibility, including the analysis of how technical improvement of plants was mainly

driven by market mechanisms.

International performance benchmark for the defined thermal power plant

categories: Rankine cycles, combined cycles and open cycles. Emissions limits are

also considered.

Technical and environmental aspects that might be a limitation for flexible

operation.

Technical definitions of the relevant concepts commonly used to characterize the

ancillary services, the technical operation of the plants and the electricity market.


The international review is followed by the analysis of the current situation in Chile and the

corresponding gap analysis. Market/grid structure and technical performance of Chilean

thermal fleet are compared to the international best practice and the most important

differences are analysed.

Finally, based on the gap analysis findings the study is concluded by a series of proposals

that aim to feed the discussion on the new regulatory framework for thermal power plants.


2. Study Cases and Analysis of International Best

Practices

2.1. Technical Definitions

This section provides the technical definitions of the relevant concepts commonly used to

characterize the ancillary services, the technical operation of the plants and the electricity

market.

When applicable, the reference to the European grid code or website from which the

definition was extracted is mentioned.

The other definitions are proposed by the authors based on Engie Lab Laborelec (ELL)

experience. They are marked with an asterisk (*).

Ancillary Services

Ancillary services [2]

Range of functions which TSOs contract so that they can guarantee system security. These

include black start capability (the ability to restart a grid following a blackout), frequency

response (Primary and Secondary frequency control), fast reserve/Tertiary Frequency

Control (which can provide additional energy when needed) and the provision of reactive

power.

Black start capability [3]

Capability of recovery of a power plant from a total shutdown through a dedicated auxiliary

power source without any electrical energy supply external to the power plant.

Control area [3]

A coherent part of the ‘Continental Europe’ of ENTSO-E Interconnected System (generally

coinciding with the territory of a country, a geographical area whose borders are physically

delimited by meters for power and energy exchanged with the remaining part of the

interconnected grid) where a single system operator is in charge, and on which the physical

loads and controllable generation are connected inside the same Control area.

Day ahead energy market [4]

The trading of bids for the purchase and supply of electrical energy for each period regarding

the next operating day following that of trading.

Droop [3]

Ratio of a steady-state change of frequency to the resulting steady-state change in active

power output, expressed in percentage terms. The change in frequency is expressed as a

ratio to nominal frequency and the change in active power expressed as a ratio to maximum

capacity or actual active power at the moment the relevant threshold is reached.

It can be expressed by the following formula:


𝑆(%) =

∆𝑓𝑓𝑛

⁄

∆𝑃𝑃𝑚𝑎𝑥

⁄

Where 𝑆 is the droop, ∆𝑓 is the variation of frequency on the grid, ∆𝑃 is the corresponding

active power to be supplied. 𝑓𝑛 and 𝑃𝑚𝑎𝑥 are the nominal frequency and maximum capacity.

Frequency response deadband (Δfmin) [3]

Interval used intentionally to make the frequency control unresponsive (Figure 1).

Intra-day market (IDM) [4]

The trading of bids and offers for the purchase and supply of electrical energy for adjusting

injection and withdrawal programmes set on the Day Ahead Energy Market.

Max frequency deviation (Δfmax) (*)

Frequency deviation from which no extra reaction is awaited (Figure 1).

Primary Frequency Control (PFC) [3]

Capability of a power plant to adjust automatically its active power output in response to a

measured deviation of system frequency from a setpoint, in order to maintain stable system

frequency (Figure 1).

Figure 1. Primary frequency control. See below for ΔPmax definition.

The PFC is also called “R1” in this report (common denomination in Belgium and Italy).

Regulation zone [3]

A portion of the ENTSO-E Interconnected System “Continental Europe”, generally coinciding

with the territory of a country or of a geographical area, physically delimitated by the location

of measurement points for the exchange of energy and power with the remaining part of the

interconnected grid.

SFC half band [4]

The maximum variation in power which can be requested in increase or decrease, with

respect to the binding programme, for SFC. The value of the half band can be different

upwards and downwards. The agreed / sold half-band amplitude can vary during the day

(Figure 2).


Figure 2. SFC Half band. The set point from the TSO is expressed in % of the half-band (α): positive values upwards, negative values downwards.

Primary Voltage Control [4]

Automatic voltage control function of a generator which aims at regulating the reactive

energy production, following a voltage variation, in order to maintain the voltage at its

reference value at the generator terminals or at the high voltage connection point of the

power station.

Secondary Frequency Control (SFC) [4]

Automatic, centralised load and frequency control which aims at regulating the production

of generators within a Control area, in order to maintain the scheduled power programmes

at the interconnection and to bring the system frequency back to its reference value.

The SFC is also called “R2” in this report (common denomination in Belgium and Italy).

Synchronous area [3]

An area covered by interconnected systems whose control areas are interconnected in a

synchronous way. The system frequency is equal for the entire synchronous area.

Tertiary Frequency Control (*)

Production capacity made available to the Transmission System Operator, representing the

provided amount of production that can be activated as increasing production (upward

tertiary reserve) or decreasing production (downward tertiary reserve) for the purpose of

balancing.

After the reaction of the PFC and SFC, it allows the TSO to reconstitute the reserve of power

available on the grid. Units participating to the tertiary Control are requested to start within

a very short time (15 to 30 min in Western Europe) and to produce a certain amount of MW

previously agreed with the TSO (Figure 3).


Figure 3. Tertiary Frequency Control

The TFC is also called “R3” in this report (common denomination in Belgium and Italy).

Very Fast Reserve - VFR (ΔPmax) [4]

Production capacity [MW] made available to the Transmission System Operator,

representing the provided amount of production that can be regulated subject to the Primary

Frequency Control.

The VFR should be produced/removed in a very short time (typically 30s in Europe),

proportionally to the frequency deviation.

Operational Parameters (*)

Reference Site Conditions (RSC)

Reference ambient temperature, relative humidity and atmospheric pressure of a power

plant. They can be ISO or site average conditions.

In practice, correction curves are applied on the heat rate and the power output of the unit

to represent a situation in reference conditions. For example in Figure 4, correction factor

are applied for ambient temperature on heat rate and power output to represent a situation

at 19°C.

Figure 4: Example of a correction factor for ambient temperature applied on the power output and the heat rate of a GT


Net power output

Net active power injected into the high voltage grid and useful from a market point of view

(i.e. after removal of the auxiliary and power losses in the step up transformer, among

others).

Figure 5: Definition – Gross and net active power

In general, gross power is measured at the terminal of the generator, and net power at the

terminal of the step-up transformer (Figure 5).

Maximum capacity (Pmax)

Maximum net active power that could be produced, transmitted or distributed continuously

throughout an unlimited period of operation at RSC (Figure 6).

Figure 6: Definition - Pmax

In some literature, such as [5], Pmax is also named Maximum Continuous Rating (MCR).

Maximum capacity in exceptional conditions (Pmax exceptional)

Maximum net active power that could be produced, transmitted or distributed in exceptional

operating conditions for a limited time at RSC (Figure 7).

Time limitation can be due to technical and/or economic reasons.


Figure 7: Definition Pmax exceptional

Minimum power output (Pmin)

Minimum net active power that a unit can produce, transmit or distribute continuously

throughout an unlimited period of operation in defined technical circumstances (e.g. while

complying, or not, to emission limitations) and at RSC (Figure 8).

Figure 8: Definition - Pmin

Environnemental minimum power output (Pmin_env)

Minimum net active power that a unit can produce, transmit or distribute continuously at

RSC and for which the power plant complies with the emission limits.

Technical minimum power output (Pmin_tech)

Minimum active power down to which the power plant can control active power, without

necessarily complying with the emission limits.

Minimum power output in exceptional conditions (Pmin exceptional)

Minimum net active power that a unit can produce, transmit or distribute continuously in

exceptional operating conditions for a limited time at RSC (Figure 9).

Time limitation can be due to technical and/or economic reasons.


Figure 9: Definition – Pmin exceptional

Pmin, Pmin_tech and Pmin_env are often the same but not systematically.

In a CCGT for example Pmin_env could correspond to an operation with the ST by-pass open.

In that case Pmin_env would be equal to “Pmin exceptional” (limited number of operating hours

considering the impact on the heat rate of the unit).

In this report, unless otherwise specified, Pmin refers to Pmin_env.

Turndown

Difference between maximum and minimum load (Figure 10). It can be defined in two ways:

Absolute turndown [MW]: Pmax – Pmin

Relative turndown [%] : 1 – (Pmin/Pmax)

The turndown represents the range of operation in normal conditions. The higher the

turndown, the higher the operating range.

Figure 10: Definition - Turndown

There is no convention for this definition. In some technical literatures, such as [5],

the relative turndown is defined as Pmin/ Pmax. 1 – (Pmin/Pmax) is preferred

definition for ELL since the higher the relative turndown the more flexible will be the

power plant.

De-rating on Pmax for PFC (ΔPR1)

Decrease of power output from Pmax at nominal frequency which is required to supply the

VFR in compliance with the requirements of the TSO.


Up-rating on Pmin for PFC (ΔPR1)

Increase of power output from Pmin at nominal frequency which is required to supply the VFR

in compliance with the requirements of the TSO.

Figure 11: Definition – Derating on Pmax and uprating on Pmin

Standard ramp rate

Maximum allowable power output gradient (expressed in MW/min) on the full operating

range (i.e.: which can be considered for the load changes).

Some gas turbines may be limited in specific load ranges (e.g. at very high load).

Higher values are usually allowed for Primary Frequency Control, and sometimes for

Secondary Frequency Control.

Figure 12: Definition - Ramp rate

In some technical literatures, such as [5], ramp rates can also be expressed in percent of

Pmax per minute (% Pmax/min). This is called relative ramp rate.

(Minimum) downtime and uptime

The downtime is the time between a shutdown and the moment a unit is restarted.

The uptime is the time between the synchronization and the moment a unit is shut down.

These parameters are usually referred as minimum downtime and minimum uptime, which

are respectively the minimum time a unit shall be kept offline, and the minimum time a unit

shall be kept online.

There is no convention for these definitions. There may be differences from one

manufacturer to another, or from one grid code to another.


Start-up

A start-up is a process which typically leads a thermal plant from the state “Ready to start”

to Pmin. A typical start-up consists in the following sequences:

■ Boiler purging (Rankine and CCGTs only)

■ Run up: ignition to synchronization

■ Load increase: from synchronization to Pmin

The thermal plant should be able to provide power at the standard ramp rate as from the

end of the start-up.

Typical start-up are represented in Figure 13 for Rankine cycles, Figure 14 for CCGTs and

Figure 15 for OCGTs.

Figure 13: Definition - Start-up process (Rankine)

Figure 14: Definition - Start-up process (CCGT)


Figure 15: Definition - Start-up process (OCGT)

There is no convention for this definition. There may be differences from one

manufacturer to another, or from one grid code to another. Besides, the time scale in

the figures are not representative.

The duration of a start-up strongly depends on the physical state of the unit, in particular the

temperature and pressure in the different components of the unit, and more specifically the

boiler and the steam turbine. Power plants with a short downtime will keep higher

temperature and pressure and will be able to return to service more quickly [6].

Different categories of start-ups can thus be defined, according to the downtime preceding

the re-start of the unit, the temperature, or the pressure in the different components of the

unit. This is usually defined either by the power utilities, the manufacturers, or the grid codes.

In this report, the convention used for the power plants of ENGIE in Europe is taken:

■ Cold start-up: 72h+ after shutdown

■ Warm start-up: between 12h and 72h after shutdown

■ Hot start-up: less than 12h after shut down for a CCGT, and 8h for Rankine cycles.

In the definition proposed by ELL the preparation time is not included in the start-up time

since it strongly relies on the operational state of the power plant at the moment of the

request to start from the TSO.

For example, for a CCGT, in case of an unexpected request to start from the TSO, typical

preparation times are represented in Figure 16.


Figure 16: Typical preparation times for a CCGT. Preparation times vary from a few dozen of minutes for a hot start-up with the vacuum kept in the condenser to more than 10 hours for a cold start-up,

after an overhaul of the boiler (i.e. boiler dry)

Electricity market

Aggregator [7]

An Aggregator is a buyer's agent that joins customers together as a single purchasing unit

and negotiates on their behalf for the purchase of electricity service.

Implicit Auctions [8]

In implicit auctions (also known as market coupling) electricity and capacity are traded

together, enabling electricity to be moved from one power exchange to another power

exchange.

Installed capacity (*)

Installed capacity or rated capacity, is the maximum capacity that a system is designed to

run at.

Merit Order [9]

The merit order is a way of ranking available electrical generation, based on ascending order

of price (which may reflect the order of their short-run marginal costs of production) together

with amount of energy that will be generated. In a centralized management, the ranking is

so that those with the lowest marginal costs are the first ones to be brought online to meet

demand, and the plants with the highest marginal costs are the last to be brought on line.

Dispatching generation in this way minimizes the cost of production of electricity.

Sometimes generating units must be started out of merit order, due to transmission

congestion, system reliability or other reasons.

Pay-as-bid [10]

“Pay-as-bid” or “discriminatory price” auction is an auction where all suppliers receive the

price they bided for the offered electricity. Hence, suppliers receive different prices for the

same commodity.

In pay-as-bid system, the suppliers are incentivized to estimate the cost of the “marginal bid”

(most expensive supplier balancing supply and demand) and ask more than their own


marginal cost. Some suppliers are not selected because they made a wrong estimation of

the marginal bid.

Pay-as-cleared [10]

“Pay-as-cleared” or “uniform price” auction is an auction where all suppliers receive the

same price for the offered electricity (market price). The price is determined by the balance

between supply and demand (i.e. most expensive unit selected in the merit order). See

Figure 17.

In pay-as-cleared system, the suppliers are incentivized to bid at their own marginal cost in

order to maximize the probability of being selected. Welfare is maximized: the cheapest

suppliers are selected.

Figure 17 – “pay-as-bid” vs “pay-as-cleared” [10]. Same average price is assumed in this illustration but it is not the case in reality.

Spark spread

Theoretical gross margin of a power plant from selling a unit of electricity, having bought the

fuel required to produce this unit of electricity.

A difference is typically made between “clean” spark spread for gas plants and the “dark”

spark spread for coal plants.

2.2. European context [11]

Evolution of the electricity market liberalisation in EU [12]

During the 1990s, most national electricity and natural gas markets were still monopolies.

The European Union and the Member States decided to open these markets to competition

gradually. In particular, the European Union decided to:

distinguish clearly between competitive parts of the industry (e.g. supply to

customers) and non-competitive parts (e.g. operation of the networks);

oblige the operators of the non-competitive parts of the industry (e.g. the networks

and other infrastructure) to allow third parties to have access to the infrastructure;

free up the supply side of the market (e.g. remove barriers preventing alternative

suppliers from importing or producing energy);


remove gradually any restrictions on customers from changing their supplier;

introduce independent regulators to monitor the sector;

The first liberalisation directives for the electricity market were adopted in 1996 (96/92/EC

Directive) and had to be transposed into Member States' legal systems by 1998. The logic

was a price unification and the integration of different national markets, laying the foundation

of the creation of a common European power market.

The 96/92/EC Directive established, for the first time in Europe, common rules for the

generation, transmission and distribution of electricity, creating a common body of laws

relating to the organization and functioning of the electricity sector, the access to the market,

the criteria and procedures applicable to calls for tender and the granting of authorizations

and the operation of systems.

The Directive provided that every Member State had to designate a system operator (TSO),

to be responsible for managing their national transmission system, in order to ensure the

transmission of electricity, the security of supply and the connections between different

national systems. This system operator had to avoid discriminations between users or

classes of users.

The main goal of the 96/92/EC Directive was to ensure the opening of EU electricity market,

giving the possibility to “eligible” customers to choose their own electricity supplier (both

national and foreign suppliers). In practice, only some industrial customers were able to

select their suppliers. The Directive also obliged Member States to control and, if necessary,

weaken local or national monopolists by giving the possibility to other competitors to enter

the market.

The application of the directive in the different countries was quite diverse, as the situations

were very different: some countries were already facing market competition (e.g. Spain,

Germany, Belgium or UK). In other countries, the governments were still major shareholders

of the main utilities. And in some countries, the power sector was in the hands of monopolies

(e.g. Italy, France).

The second liberalisation directives were adopted in 2003 (2003/54/EC Directive) and

were to be transposed into national law by Member States by 2004, with some provisions

entering into force only in 2007.

Despite the innovation introduced by the first directive, there were still too many differences

between different national markets. Although Directive 96/92/EC had allowed a step forward

for the creation of an internal electricity market, it was also clear that there were many

improvements to apply. In particular, Member States were worried about market dominance

in national markets.

The main consequences of the directive was that every consumer (not only the “eligible”

ones) was entitled to choose its supplier by July 1st 2004 for industrial customers and July

1st 2007 for domestic customers.

It also imposed to the Member States to unbundle the transmission systems and the

transmission system operators.

Although significant progress had been made, competition was slow to take off, with markets

remaining largely national (relatively little cross-border trade), and highly concentrated.

Companies trying to enter the market, business leaders, parliamentarians, and consumer

groups were concerned about the slow development of wholesale gas and electricity


markets, high prices and limited choice for consumers. The Commission therefore launched

a sector inquiry in 2005 to identify the barriers preventing more competition in these markets.

The results were published in 2007.

Based on the Commission's energy package of January 2007, including the results of the

sector inquiry, the Commission brought forward in September 2007 legislative proposals

(third liberalisation package) to strengthen competition in the electricity and gas markets.

It also integrates the 20-20-20 Policy requirements (reduce consumption of primary energy

by 20%, reduce by 20% gas emissions and include at least 20% of renewable energies in

energy consumption by 2020).

This package entered into force in 2009 (2009/72/EC Directive).

Core elements of the third package include ownership unbundling, which stipulates the

separation of companies' generation and sale operations from their transmission networks,

and the establishment of a National Regulatory Authority (NRA) for each Member State. It

also supported the creation of the ENTSO-E.

In recent years electricity wholesale markets have developed in most Member States which

allow the electricity producers, the large suppliers and some customers to trade standard

contracts in electricity (e.g. a base load contract for the following calendar year whereby a

constant amount of electricity is supplied every hour for the whole year to come; or base

load contracts for the days, weeks or months ahead; or peak load contracts, etc.). The

wholesale markets play a key role in the electricity sector as they set the prices that are then

passed on in some way to the retail customers.

Overview of EU energy market

2.2.2.1. Grid management

The development of the European internal electricity market leads to increasing long-

distance and inter-area power flows as the interconnected transmission systems serve as

the wholesale market platform. Combined with the development of RES, it pushed the

system to operate closer to the security and stability limits.

In Europe, the responsibility for transmission security and reliability is assigned to the TSOs

for their Control Areas, as defined by the national regulation. The TSOs are responsible for

all measures to preserve the system security and improve system adequacy to the new

electricity market.

The ENTSO-E was founded in 2008 and represents 42 TSOs from 34 countries (828 GW

generation). It can be considered as the “TSO of TSOs” and issued a grid code in April 2016

which is legally binding at European level (“Commission Regulation 2016/631”) [3]. This grid

code has now to be translated into the national grid codes, which can impose more stringent

requirements (specific approaches and parameters like threshold values).

The grid code should make sure that generation facilities connected to the transmission grid

contribute to a safe system operation but also supply ancillary services in order to preserve

system security (balancing) and improve system adequacy (i.a. RES variations).

The main requirements to generation facilities can be summarized as follows:

- Provisions of information for system management;

- System balancing / frequency stability;


- Voltage stability;

- Robustness of generating units against perturbations (stable operation);

- System restoration after a disturbance;

In the current context of larger RES integration, these requirements are focused on more

“flexibility”, which can be defined as the capability of the system to adapt to foreseen and

unforeseen changes. Table 1 shows examples of the mentioned changes and mechanisms

that may be used by TSOs to ensure system stability.

Table 1. Examples of foreseen and unforeseen changes of load and demand sides

Foreseen changes Unforeseen changes

Examples Projection on load Residual demand steep change Normal start-up time of a power plant

Prediction error on supply/demand Trip of a plant

Levers Merchant energy markets (day-ahead, intraday, forwards) Strategic reserve (TSO)

Regulated ancillary market (TSO)

Renewables both affect the foreseen changes (“duck curve”) with higher residual load

changes as well as the unforeseen changes (bad predictions, quick change of wind or

irradiation). As an example of the foreseen changes (“duck curve”), Figure 18 shows a

prediction of the demand in Chile for 2021 [13]. This figure eloquently shows the expected

residual demand variation during a day.

Figure 18 - "Duck curve" on the residual load for Chile in 2021 [13]

2.2.2.2. Electricity markets

Role of markets

The adequacy between the energy supply and demand is mainly managed by merchant

markets (Day Ahead and Intraday). The residual imbalance (starting 1h before real time) is


then managed by the TSOs with contracted ancillaries that can be activated curatively (e.g.

frequency change) but also preventively (anticipation of power shortage). Figure 19 shows

graphically the roles of merchant and regulated markets.

Figure 19 - merchant vs regulated markets (source: ENGIE – CEEME)

For foreseen unbalances which cannot be solved by the markets (e.g.: large unbalances on

the day-ahead market), an additional (regulated) capacity market managed by the TSO

might also be required to ensure system stability (e.g. “strategic reserve” in Belgium).

Market coupling

In order to improve the integration of their energy markets, most of the European TSOs have

coupled their day-ahead markets. The result is a larger platform where market offers and

demands can meet, provided that sufficient cross-border capacity is available. Figure 20

shows an example of cross-border power exchanges between countries in a single day. In

colours are highlighted the countries which are exporters, importers and those who are in a

balance situation.

The market coupling mechanism means that the market players of a country have direct

access to the other countries markets. The mechanism leads to price convergence on all

markets, as far as possible. However, price differences may still occur if the capacity

available for cross-border trades is insufficient to meet the total demand.

With market coupling, the daily cross-border transmission capacity between the various

areas is not explicitly auctioned among the market parties, but is implicitly made available

via energy transactions on the power exchanges on either side of the border (hence the

term implicit auction). It means that the buyers and sellers on a power exchange benefit

automatically from cross-border exchanges without the need to explicitly acquire the

corresponding transmission capacity.

The primary aim of the mechanism is to improve market liquidity and consequently, to induce

lower and more stable electricity prices. The power exchanges Belpex (Belgium), APX (The

Netherlands), EPEX Spot (Germany and France), Nord Pool Spot (Norway, Sweden,

Finland, and Denmark), OMIE (Spain and Portugal) and GME (Italy) are currently coupled.

With market coupling, purchase bids in one country are matched up with sales bids in

another country, where the price may be lower. The purchase/sales bids made in the

different markets are pooled and then matched up by financial merit order. As a result, less

expensive energy produced in one country can be used to meet high demand in another

country. If there are no cross-border capacity constraints, the market coupling mechanism

will promote the emergence of a single price for all markets. The coupling mechanism

therefore makes a significant contribution to improving energy market liquidity. In practice


there are currently still price differences across the European market when the

interconnections capacity is reached.

Price Coupling of Regions (PCR) is the project of European Power Exchanges to develop a

single price coupling solution to be used to calculate electricity prices across Europe

respecting the capacity of the relevant network elements on a day-ahead basis.

The PCR-coupled area now covers 19 countries, standing for about 85% of European power

consumption. It is called “Multi-Regional Coupling” (MRC).

Figure 20: Example of cross-border exchanges between different power markets (source: ENTSO-E)

ENTSO-E technical requirements [3]

2.2.3.1. Ancillary services

This section provides an overview (not exhaustive) of the main ENTSO-E requirements for

“type D” generators. These requirements are then translated by the local TSOs on the grid

code for their own Control Areas (they can be more stringent).

The requirements applicable to type D power-generating modules should be specific to

“higher voltage connected generation with an impact on control and operation of the entire

system. They should ensure stable operation of the interconnected system, allowing the use

of ancillary services from generation Europe-wide”. For Continental Europe, the minimum

power threshold for type D generators is 75MW.

Other requirements (less stringent) exist for lower capacity generators (types “A”, “B” and

“C”).

There are currently no requirements for the RES in ENTSO-E grid code. However, ENTSO-

E pushes the TSOs to create specific ancillary services products which allow their

participation.

Primary Frequency Response

The following limits are imposed by ENTSO-E:

- Maximum frequency deviation (Δfmax): 200 mHz for Continental Europe (CE)


- VFR (ΔPmax): 1.5 - 10% of the nominal capacity

- Droop: 2 – 12%

- Time to supply the VFR: 30s max

- Frequency response deadband: 0 – +/- 500 mHz (for CE: +/-10 mHz)

- Activation delay: max 2 sec (or to be justified)

For downward frequency deviations, the power plant shall be able to provide a power

increase up to its maximum capacity. In addition, stable operation shall be ensured.

The power plant shall be capable of providing full active power frequency response for a

period of between 15 and 30 minutes as specified by the relevant TSO.

Signals shall be foreseen to enable real-time monitoring of the PFR by the TSO.

Secondary Frequency Response

The power plant control system shall be capable of adjusting an active power setpoint in line

with instructions given by the TSO.

The TSO shall specify a tolerance (subject to the availability of the prime mover resource)

applying to the new setpoint and the time within which it must be reached.

With regard to frequency restoration control, the power plant shall provide functionalities

complying with specifications specified by the relevant TSO, aiming at restoring frequency

to its nominal value or maintaining power exchange flows between Control Areas at their

scheduled values.

Voltage control

The relevant system operator in coordination with the relevant TSO shall specify the reactive

power provision capability requirements in the context of varying voltage.

The ENTSO-E gives minimum requirements on the operating area for reactive power supply

profile at Maximum Capacity (“U-Q/Pmax”) which should be agreed with the TSO. When

operating at an active power output below the Maximum Capacity (P < Pmax), the power

plant shall be capable of operating at every possible operating point in the P-Q-capability

diagram of the alternator of that plant.

ENTSO-E also specifies the requirements for the Automatic Voltage Regulator (AVR).

Ramp rates

The relevant system operator shall specify, in coordination with the relevant TSO, minimum

and maximum limits on rates of change of active power output (ramping limits) in both an up

and down direction of change of active power output for a power plant, taking into

consideration the specific characteristics of prime mover technology.

Black start

Black start is not mandatory.

A power plant with black start capability shall be capable of starting from shutdown without

any external electrical energy supply within a time frame specified by the relevant system

operator in coordination with the relevant TSO. A power plant with black start capability shall

be capable of automatically regulating dips in voltage caused by connection of demand.


2.2.3.2. Other requirements

In addition to the requirement on ancillary services, ENTSO-E also describes requirements

which guarantee the robustness of the generating units on the grid to transient events. They

are briefly described in this section.

Minimum frequency range

The ENTSO-E imposes a frequency band for which the units shall remain connected on the

network. The values imposed for Continental Europe are shown in Table 2.

Table 2 imposed operation time for each frequency range

Maximum active power reduction by falling frequency

The TSO may impose a maximum active power reduction in case of falling frequency

included in the following area:

Figure 21. Active power reduction area

Fault ride through capability

Each TSO shall specify a voltage-against-time-profile in line with Figure 22 at the connection

point for fault conditions, which describes the conditions in which the power plant is capable

of staying connected to the network and continuing to operate stably after the power system

has been disturbed by secured faults on the transmission system.


Figure 22 - ENTSO-E fault ride through requirement. Table for synchronous generator (> 110kV).

Voltage stability

A power plant shall be capable of staying connected to the network and operating within the

ranges of the network voltage at the connection point, expressed by the voltage at the

connection point related to the reference 1 pu voltage, and for the time periods specified in

the following tables for Continental Europe:

Table 3. Voltage: minimum time period without disconnecting for pu values from 110kV to 300kV

For voltages between 300 and 400kV at the connection points, it becomes:


Table 4. Voltage: minimum time period without disconnecting for pu values from 300kV to 400kV

Simulation models and tests

The TSO has the right to request that the power plant owner carries out compliance tests

which aim at demonstrating that the plant complies with the requirements of the grid code

and ancillary services. A set of simulations can replace the compliance tests if they are

reliable enough.

For the PFR, the tests can include a simulation of frequency steps to trigger the whole active

power frequency response range.

Emissions

The applicable directive at EU level is currently the IE-D (Industrial Emissions Directive)

which came into force on 01/01/2016. It replaces the LCP-D (Large Combustion Plants

Directive) which was applicable between 1990 and 2016 (with an update in 2008).

The minimum requirements on the emission limit values (ELV) are defined in the Annex V

of the IE-D. However, the “Best Available Techniques” defined in the “BREF” document

(BAT Reference Document for Large Combustion Plants [14]) should also be taken into

consideration by the authorities when granting the permits (deviations to be justified).

“BREF” document is currently in “Final Draft” version. It provides ranges of emissions which

are more stringent than the IE-D and will become mandatory as from 2021. Each Member

State will have to define its interpretation of the BREF and the selected value within the

suggested range.

The limits are summarized in Table 5 for existing Rankine units with a thermal input

>300MWth, CCGTs with a thermal input between 50 and 600 MWth and existing OCGTs.

More stringent limits are applicable for new plants.

The tables are only applicable for “normal conditions”. Hence they exclude start-up and shut-

down phases. In addition, the limits for OCGT and CCGT do not apply below 70% load.

The directive is minimum requirement for the Member States. More stringent requirements

are usually imposed at local level by the relevant authority (case-by-case requirements

specified in the permit). Additional requirements can also be imposed at regional or national

level (e.g. VLAREM for the Flemish region in Belgium). They can include a limitation on the

concentration or on the total emitted mass of pollutants.


Table 5. Emission limit values for units with thermal input > 300MWth in mg/Nm³

Technology IED1 Final Draft BREF LCP

(day/year)

Coal (pulverized coal)

@6% O2

NOx: 200 SO2: 200 PM: 20 CO: -

NOx: 80-165 / 65-150 SO2: 25-165 / 10-130 PM: 3-20 / 2-12 CO: - / 1-100

CCGT

@15% O2

NOx: 50 SO2: - PM: - CO: 100

NOx: 35-55 / 10-45 SO2: - PM: - CO: - / 5-40

OCGT

@15% O2

NOx: 50 SO2: - PM: - CO: 100

NOx: 7-75 / 6-50 SO2: - PM: - CO: - / 3-40

The two documents set emission levels for dust, or total PM which is the total

particulate matter emitted into the air. The diameter of the PM (e.g. PM10 or

PM2.5) is not specified.

2.3. Description of the Italian Flexibility Market

Overview of the Italian market [15]

Italy is located in Southern Europe. To the North, Italy borders France, Switzerland, Austria,

and Slovenia, and is roughly delimited by the Alps chain. To the South, it consists of the

complete Italian Peninsula and the two Mediterranean islands of Sicily and Sardinia.

The population of Italy is ~60 million inhabitants for a total area of ~300 000 km².

The “antenna” structure of the electrical network is a

consequence of the particular shape of the country.

Moreover the Alps barrier limits the potential for

interconnections with the border countries. The

geographical configuration of Italy makes it quite

comparable with the Chilean System.

TERNA is the unique TSO for the whole country. According to the latest statistics available

on the ENTSO-e web site, the installed capacity in Italy was around 103 GW in 2014 with

the breakdown detailed in Table 6.

1 The condition of application of the ELVs in the IE-D are the following: • Monthly average emission values shall not exceed the ELVs • Daily average emission values shall not exceed 110% of the ELVs • 95% of all the hourly emission average values over the year shall not exceed 200% of the ELVs


Table 6. Installed capacity breakdown - Italy

Production Type - IT 2014 [MW]

Biomass 934 Fossil Coal-derived gas 407 Fossil Gas 20796 Fossil Hard coal 1360 Fossil Oil 5017 Geothermal 869 Hydro Pumped Storage 4714 Hydro Run-of-river 10719 Hydro Water Reservoir 6362 Other 37816 Solar 4980 Waste 116 Wind Offshore 2 Wind Onshore 8455

Total Grand capacity 102547

Market organization [16]

Figure 23. Italian Market organization

As shown in Figure 23, the Italian Electricity Market is organized in two main markets:

MPE: a Spot Electricity Market covering a short term horizon

MTE: a Forward Electricity Market covering a longer term horizon

The Spot Electricity Market (MPE) consists of the following submarkets:

Day-Ahead Market (MGP, Mercato del Giorno Prima), where producers,

wholesalers and eligible customers can sell/buy electricity for the next day;

Intraday Market (MI, Mercato Infragiornaliero), where producers, wholesalers and

eligible customers can modify their injection/withdrawal schedules resulting from

the Day-Ahead Market;

Italian Electricity Market

MPE

Spot

MGP

Day-Ahead

MI

Intraday

MSD

Ancillariy services

MTE

Forward

MTE IDEX


Ancillary Services Market (MSD, Mercato dei Servizi di Dispacciamento), where

TERNA, the TSO, procures the ancillary services which are necessary for the safe

management and control of the power system (regulated market).

The Forward Electricity Market (MTE) is organized as:

Forward market MTE: forward electricity contracts where physical delivery and

withdrawal obligation are traded

IDEX Market and CDE platform: market for Electricity Derivatives operated by

Borsa Italiana

GME (Gestore dei Mercati Energetici) carries out dispatching activities on behalf of TERNA,

the TSO.

2.3.2.1. Day ahead market

In the Day-Ahead Market (MGP), which hosts most of the electricity sale and purchase

transactions, hourly energy blocks are traded for the next day. In this market, participation

is optional. In 2015 a volume of 235 TWh was traded in this market.

The price offered on this market are based on the marginal costs of the plants.

Organisation:

Participants submit offers/bids where they specify the quantity of energy and the

minimum/maximum price at which they are willing to sell/purchase electricity.

Supply offers may only refer to injection points and demand bids only refer to withdrawal

points.

The MGP is an auction market and not a continuous-trading market, in which bids/offers are

accepted by GME under the economic merit-order criterion and taking into account the

transmission capacity limits between Italian market zones.

To solve the market, the GME sort bids by ascending price for sellers and by descending

price for buyers.

Intersection between supply curve and demand curve is the system equilibrium: it defines

both the equilibrium price (system marginal price, that is equal to the price of the last bid

accepted, based on the economic merit order) and the awarded quantity for sellers and

buyers.

In Italy, the market price is mostly driven by gas assets which are called in the merit order

ranking even for low residual demands. It is not expected to change in the near future.

Particularities:

Due to its configuration in antenna, the Italian electrical system is divided in six areas:

Northern, Central Northern, Central Southern, Southern, Sicilia and Sardinia (islands)

(Figure 24). These market zones are defined on the basis of three main criteria:

1. transmission capacity towards or from other zones is constrained

2. there is no intra-zonal congestion

3. location of injection and withdrawal points within a zone does not affect transport

capacity between zones


Figure 24 – Market zones and prices on January 12th 2017 12:00 ( [17])

A pricing algorithm takes into account the maximum transport capacity between market

zones, as identified by the TSO. When the maximum capacity is not exceeded, a single

price emerges on the market. When the maximum capacity is exceeded, the market splits

into separate market zones: for each of them a supply and a demand curve are determined

by GME and a different equilibrium is set (“Zonal Clearing Price”).

Three of the five borders of the Italian Borders are coupled with the Multi-Regional Coupling

(MRC).

Market scheduling:

Accepted offers/bids on MGP determine the preliminary “injection and withdrawal

schedules” of each injection/withdrawal point for the next day. The MGP session opens at

8:00 AM of the ninth day before the day of delivery and closes at 12:00 PM of the day before

the day of delivery. The results of the MGP are available by 12.55 PM of the day before the

day of delivery.

2.3.2.2. Intraday market

The Intraday Market (MI) allows market participants to modify the injection and withdrawal

schedules defined in the MGP by submitting additional supply offers or demand bids. As for

the MGP, the participation to the MI is also optional and GME acts as a central counterparty.

In 2015 a volume of 25 TWh has been traded in this market

Supply offers and demand bids are selected under the same criterion applied to the MGP.

Therefore, GME accepts offers/bids submitted into the MI by Merit Order, taking into account

the transmission limits remaining after the Day-Ahead Market. In the MI all accepted

offers/bids are remunerated at the Zonal Clearing Price.

Accepted offers/bids in the MI modify the preliminary schedules and determine the

revised/updated injection and withdrawal schedules of each offer point for the day of

delivery.

In order to simulate a frequency similar to that of continuous trading, the MI takes place in

five sessions which are organized in the form of Implicit Auctions. In practice exchanges on

this market occur up to 2-3 hours before the delivery. After that time, the balancing is

performed by the TSO with the ancillary services (fully centralized dispatching).


2.3.2.3. Ancillary Services Market

In the Ancillary Services Market (MSD), TERNA procures the resources that it requires for

managing, operating, monitoring and controlling the power system (relief of intra-zonal

congestions, creation of secondary and tertiary reserve margins, real-time balancing). In this

market TERNA enters into purchase and sale contracts in order to procure the resources

for dispatching services and acts as a central counterparty.

Participation in the MSD is optional for «relevant producers» (i.e. programmable producers

with generating capacity higher than 10 MW), after obtaining a specific «qualification» from

TERNA to supply ancillary services. However, for «relevant producers» which are

«qualified» by TERNA to participate to the MSD, it is mandatory to offer/bid all up/down

control energy left over from injection schedules resulting from the MI.

In the MSD, offers/bids are accepted by economic Merit Order, taking into account the need

for ensuring the proper operation of the system, and valued at the offered price (Pay-as-bid

pricing). More precisely, TERNA accepts bids/offers in this market by minimizing the cost of

selection, which is representative not only of the procurement costs, but also of the expected

costs for the use of resources for dispatching on a daily horizon and taking into account the

efficiency and reliability of the available resources.

The MSD consists of a programming phase (ex-ante MSD) and of a real-time Balancing

Market (MB). In the ex-ante MSD, TERNA accepts energy demand bids and supply offers

in order to relieve residual congestions and to create secondary and tertiary reserve

margins. In the MB, TERNA accepts energy demand bids and supply offers in order to

activate its service of secondary control and to balance energy injections and withdrawals

into/from the grid in real time.

The ex-ante MSD and the MB take place in multiple sessions, as specified in the dispatching

rules.

Detailed remuneration principles are developed in section 2.3.4. The market is based on a

“pay-as-bid” system.

2.3.2.4. Forward market MTE, IDEX and CDE platform

Trading in the MTE takes place on the basis of continuous trading during which the

conclusion of contracts is done through the automatic matching of offers of opposite signs

present on the order book and ranked according to priority criteria.

In this market, GME acts as a central counterparty and records on the “OTC Registration

Platform” (PCE) the net position to be physically delivered, corresponding to the purchase

and sales transactions concluded by the operator in the MTE.

In the MTE, the tradable contracts are of the following types: base load and peak load with

monthly, quarterly and yearly delivery periods.

The CDE is the platform where financial electricity derivatives contracts, concluded on

“Borsa Italiana” exchange for electricity (IDEX), are executed. The contracts executed on

CDE are those for which the market participant has requested to exercise the option of

physical delivery of the underlying electricity in the Italian Electricity Market.


2.3.2.5. Capacity payments for planned shortage (“essential plants”)

There is currently no remuneration for the capacity in Italy neither on the energy markets,

nor on the ancillary markets.

However, the TSO has the right to nominate some power plants as “essential”.

The so‐called essential plants for power system security are those plants identified as

technically and structurally required for the resolution of network congestions and the

maintenance of adequate levels of security of the national electricity system, for significant

periods of time.

The essential units have to be always committed and available. They can ask a

compensation for part of their costs if they are able to demonstrate “unlikelihood that they

are capable of ensuring an adequate return on invested capital in the absence of integration

of the extra costs” [18].

A new capacity payment mechanism is being implemented, as described in section 2.3.7.

Extra considerations about the Italian system

As of February 2015 automatic coupling between Northern zone of Italy and France (3000

MW), Slovenia and Austria allow the foreign players to bid on the Italian market up to the

saturation of the available capacity.

The TSO has installed battery storage in specific areas, whereas it may normally not bias

the market with own production capability (free competition). TERNA justifies this by security

needs (balancing adjustments) and by its willingness to limit the influence of power plants

abusing of their position.

Each asset is individually responsible for its own imbalances (not at fleet nor pool of plants

level).

Unlike Belgium, industrial customers cannot participate to ancillary services yet. However,

this is currently being discussed.

Detailed information about the Ancillary Services2

As described above, TERNA operates the system in a context of very open market.

Moreover the penetration rate of RES strongly increases, making the system more difficult

to manage. Ancillary services are levers helping the TSO to ensure the correct balancing

between energy supply and demand.

The total volume exchanged on the MSD market in 2014 was 13.98 TWh up and 13.26 TWh

down. The total capacity of the plants active on this market is 70 GW, including 56 GW of

thermal plants. [19]

As a general principle, there is no compensation based on capacity (€/MW) for the ancillary

services in Italy.

The costs of the ancillary services (resulting from the remuneration schemes described in

this section) are ultimately born by the final consumers. A specific item of the electricity bills

identifies the transmission costs (including the cost of the Ancillary Services) which are

added to the cost of the energy resulting from the energy markets.

2 More details can be found in [4] Chapter 4.


As a general principle, the plants may choose to participate to the MSD for specific services,

with the important exception of the Primary Frequency Control which is mandatory. If the

plant complies with the requirements of a service (which can include a certification by a

Notified Body), it becomes an “enabled unit” for the service. The enabled units are listed in

the “Register of Production Units” which is used by the TSO and market operator for the

management of the electric system.

2.3.4.1. Primary Frequency Control – PFC (R1)

Description

The aim of the PFC, also called R1, is to quickly stabilize the frequency to a new value when

production and consumption are unbalanced. The addition of the PFC provided by all power

plants (and sometimes consumers) ensures the proportional response of an equivalent grid

controller.

In Italy, the participation to the PFC is mandatory for all types of assets, except RES.

At a technical point of view:

Only symmetrical +/- 200 mHz PFC

profile is requested

A dead band of +/- 10 mHz is foreseen

For a frequency deviation of +/- 200mHz,

a unit has to produce/retrieve 50% of its

reserve within 15 seconds and 100%

within 30 seconds

The effort has to be sustained for at least

15 minutes

These requirements are in line with ENTSO-E.

The volume of PFR is +- 1.5% of the power output of each plant3. This volume is imposed

by TERNA in order to match the ENTSOE requirements at country level. The total

participation required for each country in the European synchronous area is fixed on a yearly

basis based on the evolution of the grid capacity. The total volume is 3 GW (output of 2

major plants) and is distributed between the countries following the ratio of their total energy

generation. The total PFR reserve for continental Italy is ~320 MW. An additional 200 MW

is foreseen on Sardinia Island (isolated area). [20]

The activation of the PFC is automatic, based on the frequency deviation (no intervention

from TSO). PFC stabilizes the frequency but SFC is required to recover the nominal

frequency (50 Hz). At 50 Hz (no frequency deviation), the PFC reserve activation is 0 MW.

The TSO can report failures in the obligation to supply the reserve to the National Regulatory

Authority which can take “appropriate measures”4.

3 The minimum volume of PFR is +-10% for the plants located in Sardinia and Sicily (islands). 4 See [4] Chapter 4, section 4.4.2.3.

-200 -100 100 200 Frequency deviation [mHz]

Very Fast Reserve [MW]

0

SYMMETRICAL 200 mHz


Remuneration

Financial compensation can be received for the PFC if the Power Plant complies with several

TSO requirements: compliance tests performed by a Notified Body, installation of a quick

events recorder and possibility for the TSO to send online simulated frequency deviations.

Only the energy provided (respectively not produced) by the asset for the PFC is paid5

(respectively compensated), not the available capacity for the service itself.

Penalties

Real performances are compared online with a PFC simulation model provided by the Power

Plant and approved by the TSO (Figure 25). Financial scenarios are the following:

PFC energy provided by the power plant matches with the PFC model: in this case

a financial compensation is paid by the TSO on a quarterly hour basis;

PFC energy provided is lower than calculated: no financial compensation is offered

by the TSO for the quarterly hour considered;

PFC energy provided is systematically lower: the power plant has to provide a more

realistic model of PFC to the TSO;

In the worst cases, the power plant can lose its PFC agreement;

Figure 25. Quantification of deviation of PFC response

A financial compensation is offered for the imbalances penalties (when compared to the

injection/withdrawal schedules and R2 setpoint) caused by the PFC.

2.3.4.2. Secondary Frequency Control (R2)

Description

The aim of the R2 control is to recover the nominal frequency by rebalancing supply and

demand after the R1 action. It can be compared to the integral action of a virtual grid

controller.

The plants “enabled” for the Secondary Frequency Control service have the obligation to

bid the available capacity on the MSD.

The volume of this service was 4.8 TWh up in 2014 [21]. The typical available SFC reserve

is 800 MW (activated power is lower). [19]

5 The payment scheme is described in [4] Chapter 7, section 7.3.1.10. It is based on the Day Ahead zonal price increased by a “bonus” corresponding to 50% of the average difference between MSD offers for SFC and Day Ahead prices on an annual basis.

MODELISED PFC

REAL PFC

-200 -100 100 200 Frequency deviation

[mHz]


0

SYMMETRICAL +/- 200 mHz


[mHz]


0


FREQUENCY DEVIATION

+

-

D MODELISED/REAL PFC


To participate to the Secondary Frequency Control (i.e. become an “enabled” plant) a power

plant shall:

comply with several TSO requirements certified by a Notified Body;

follow an automatic signal sent by the TSO modulating the power between two

limits (from α = 1 corresponding to the max upward limit to α = -1 corresponding to

the max downwards limit);

be able to fully cover the half R2 band (both upward and downward) made available

to TERNA, within maximum 100 seconds;

The R2 band is not necessarily symmetrical (defined by market and technical limitations

around the set point for energy supply). In practice, the plants should be able to follow a

load set point defined by the TSO (inside the offered band) with the maximum gradient.

The TSO has to make sure that enough reserve is available for the SFC. After the closing

of the Intraday Market sessions, the TSO can instruct the plants to modify the program

resulting from the energy markets (“updated cumulated program”) to increase/decrease the

available SFC reserve (“planning phase”). The program of enabled units is fixed for each

quarter of an hour.

The load set point is adjusted continuously. Hence the plant should be able to sustain the

requested load for an unlimited time.

Remuneration

The plants have the obligation to make bids for the increase (“selling offers”) / decrease

(“buying offers”) of power from the “updated cumulative program” on the full operating range

of the plant (Pmin to Pmax). In addition, they have to offer the full available half-band.

From a financial point of view, there are two mechanisms of remuneration both based on a

“Pay as Bid” principle:

Reservation of the R2 band: if the unit is requested to reserve its R2 band

(planning phase) and modify the “updated cumulated program”, it is compensated

in line with the bid price (“selling” or “buying” offers) for the affected period of time.

Activation of the reserve (automatic signal α ≠ 0): energy injection increase /

decrease is compensated.

The bids are typically based on the plants marginal costs.

The TSO selects the bids “with the objective of minimizing the charges and maximizing the

returns resulting from activities of providing for resources for dispatching” [4].

Penalties

R2 imbalance (deviations between set point and actual power output) is penalized with the

same mechanism as for energy imbalance (see section 2.3.5).

2.3.4.3. Tertiary Frequency Control (R3)

Description

The goal for the TSO is to reconstitute its reserve once PFC and SFC have rebalanced

supply and demand.


The available tertiary reserve is offered by the plants with bids on the MSD (upwards and

downwards). The plants enabled for TFC have the obligation to bid the available capacity.

This reserve is activated manually by the TSO.

The volume of this service was 8.99 TWh up in 2014 ( [21]) and the total TFC reserve

amounts to approximately 3.5 GW [20] [21].

A difference is made between the Tertiary Fast Reserve (Riserva Terziaria Pronta) and the

Tertiary Replacement Reserve (Riserva Terziaria di Sostituzione).

The former is mainly provided by pumped hydro plants and has to start within 15’. Its

capacity is around 1.5 GW [22], [19].

The latter is mainly constituted by thermal plants (mostly gas plants). The technical

constraints are to provide a contractual load within a contractual time limit (case by case

and not necessarily 15’), the maximum start-up time being 120 min. In practice, the start-up

time of thermal plants is not key for this service.

Remuneration (thermal plants)

Auction/biding on the day ahead market:

The supplier is allowed to bid at a price reflecting the willingness to be called if no

capacity is selected in the day ahead energy market;

Only energy produced is paid, not the capacity nor the availability;

Remuneration consists in:

Token: linked to availability to restart a power plant following a specific ramp up /

ramp down defined by the TSO (compensation for the start-up);

Pay-as-bid price (compensation for the energy);

For R3, the plant is only paid if it is called, based on the energy provided at a pay-as-bid

price (and/or possible token). Hence, there is no compensation for the “stand-by” time and

related costs if the plant is not called. The pay-as-bid price can be very high (willingness to

be called).

Penalties

R3 imbalance is penalized with the same mechanism as for energy imbalance (see section

2.3.5).

2.3.4.4. Black start

Description

The purpose is to rebuild the grid in case of blackout (without external supply).

These units are part of the “Essential plants”.

Remuneration

The payment is based on a specific “fee” which is not communicated (bilateral negotiation

between the TSO and owner of a plant).


2.3.4.5. Reactive power supply

Description

The purpose is to maintain the grid voltage. Minimum ENTSO-E requirements are given in

section 2.2.3.1.

Remuneration

No specific remuneration is foreseen for this service.

A Power Plant can be called to sustain voltage. It will be paid for the energy provided, not

for the service.

Energy imbalance penalties

Imbalances are penalized, including those caused by the PFC (R1) but the TSO takes into

consideration its own situation regarding the Area Control Error (ACE): penalties will be

heavy if the effect reinforces the ACE imbalance, they will be reduced if the result helps the

TSO to maintain the system balanced.

Figure 26. Energy Imbalance penalties

In case of undersupply in a grid shortage configuration (“short” unit, in a “short” area), the

missing energy is paid at the cost of the most expensive activated energy supply on the

ancillary market.

In case of oversupply in a grid oversupply configuration (“long” unit, in a “long” area), the

additional energy is paid at the cost of the cheapest activated energy supply on the ancillary

market (down to zero).

All imbalances are computed at the level of individual power plants.

The resulting unbalancing fees are directly invoiced by the TSO to the plant owners.


Summary table and key highlights

Table 7. Italian flexibility market summary table

Product Description Requirements Payment

Energy Day ahead and Intraday markets

Forward market

Balancing supply/demand

At plant level (no pooling)

Bid mechanism and “Pay-as-clear” market price

Ancillary - R1 Automatically activated

100% < 30s

Available for 15min

Certified by a Notified Body + online tests

No link with R2

Applicable to all plants, excepted RES

Symmetric

Not for capacity

Energy: fixed compensation

Ancillary - R2 Set point from the TSO

100% of ½ band < 100s

Unlimited time

Certified by a Notified Body

Upwards and downwards (can be asymmetric)

Not for capacity

Energy: pay-as-bid (if activated)

Ancillary - R3 Manually activated

Contractual start-up time

Upwards and downwards

Not for capacity


Essential plants

Grid security for possible power shortage (active/reactive supply) or congestions

Contractual agreement

“extra costs” compensation

Other key highlights:

All grid requirements and energy balancing are imposed at plant level

Penalties are always applied in case of imbalance with respect to the plant

production schedule

Zonal prices are applied when the inter-zonal capacities are saturated

No capacity remuneration is foreseen for ancillary services

Black start is remunerated but not voltage control

Market evolution [23]

In Italy, the 96/92/EC Directive was adopted in 1999, through the passage of the law

79/1999, also called “Decreto Bersani”.

ENEL (the historical state utility) was legally forced to sell part of its capacity, in order to

sustain new operators' entry. The power plants that ENEL was obliged to sell (15 000 MW

over a total capacity of 57 000 MW) were grouped in three societies, the so called “GenCos”

(Generation Company). These firms were Eurogen, Elettrogen and Interpower and were

made of thermoelectric and hydroelectric plants. In the two-year period 2001-2002 the

government sold the GenCos to private companies.

After the liberalisation, the network and dispatching management were transferred from

ENEL to TERNA which has been listed in the Italian Stock Exchange since 2004.

A new capacity market mechanism, open to foreign producers, should be implemented as

from 2017 (AEEGSI resolution ARG/elt 98/11). The plants would receive a yearly premium


(pay as bid) and would be obliged to submit the contracted capacity on the Day Ahead or

Ancillary markets. The revenues on the energy market will be capped at a “strike price”

corresponding to the variable costs of peak technology (the plants would not benefit from

peak prices on electricity spot market as they are remunerated for their capacity). This

mechanism will also integrate the active participation of the demand side, RES and

distributed generation (currently not involved in ancillary services). This scheme shall

receive the approval of the European Commission for the conformity to the rules of the

common energy market (one of the condition being the participation of foreign plants).

2.4. Description of the Belgian Flexibility Market

Overview of the Belgian Market [24]

Belgium is a country in Western Europe surrounded by France, the Netherlands, Germany,

Luxembourg, and the North Sea. It is a small, densely populated country which covers an

area of ~30 500 km² and has a population of about 11 million

people.

ELIA, the TSO of the country, has to manage a highly meshed

electrical network. The area constituted by France, Belgium,

and the Netherlands is called “copper plate” thanks to the

strong interconnections, exchanges and transit capacities

between the countries.

According to the latest statistics available on the ENTSO-e website, the installed capacity in

Belgium is around 19 GW in 2016 with the following breakdown:

Fuel Type - BE 2016 [MW]

Biomass 710 Fossil Gas 5373 Fossil Hard coal 470 Fossil Oil 145 Hydro Pumped Storage 1308 Hydro Run-of-river 117 Nuclear 5919 Solar 2953 Waste 368 Wind Offshore 712 Wind Onshore 1249

Total Grand capacity 19324 Figure 27. . Installed capacity breakdown – Belgium

Market Organization [25]

The responsibility of ELIA, the Belgian TSO, is to permanently ensure the balance between

production and consumption. However Access Responsible Parties (ARPs) are appointed

at every grid access point (injection or offtake point) to support it in this mission.

An ARP:


is in charge of maintaining on a quarter-hourly basis the balance between all grid

users (injections and offtakes), for which he is contracted;

may be an electricity producer, a major consumer, an electricity supplier or a trader;

can use a hub (common platform) to exchange energy with other ARPs for the

same day or the following day in order to maintain the balance in its area of

responsibility; The platform is provided to the market players free of charge.

ARPs may use the different plants in their scope as a “pool” in order to fulfil their obligations

towards the grid (balancing, ancillary services, etc.).

Besides the ARP, the overall market organization in Belgium is similar to Italy.

2.4.2.1. Day ahead market

In the day-ahead hub, any market player having the role of ARP has to maintain the quarter-

hourly balance between the offtakes and injections in its perimeter. Quarter-hourly balance

is needed in both real time and in the forecast phase. There are different types of offtakes

and injections depending on whether:

the ARP is responsible for physical offtake at an access point (in the Elia grid or

Distribution System Operators’ grids (DSOs grids);

the ARP is responsible for physical injection at an access point (in the Elia grid or

DSOs’ grids);

the ARP is exchanging energy with another ARP in the Elia control area;

the ARP is importing or exporting energy across the border with France, Germany

or the Netherlands.

As mentioned above, one of the possibilities for an ARP is to make energy transfers with

another ARP in the ELIA Control Area. Transactions may be made between parties which

do not have generation assets in Belgium (e.g. foreign traders).

The ARPs operating on the day-ahead hub use it to perform various types of energy

exchange operations. They can, for example:

make purchases or sales (i.e. bilateral trading contracts);

distribute volumes of energy amongst various subsidiaries in a single group of

companies;

act as a relay in the European energy transit (France – Belgium – the Netherlands);

share with another ARP the energy taken off the grid by an industrial customer or

injected into the grid by a production unit. They do this without having to sign a

specific access contract with Elia relating to the access to the network (mandatory

for direct off-takes and/or injections);

submit bids for energy purchases or sales on the Belgian power exchange

(Belpex);

Foreign producers are recorded as “ARPs” in Belgium for cross-border energy exchanges.

An important feature of the Belpex is its strong coupling with other Power Exchanges in the

region. Belgium was one of the first markets to be coupled as the system has been used

since 2006 (trilateral market coupling between the Netherlands, Belgium and France).


In practice, the price on the “copper plate” market (Benelux, France, Germany) are currently

very similar most of the time. They get “uncoupled” (totally or partially) only when the cross-

border lines get saturated (it can happen during a limited period at specific time of the day).

The total volume traded on the Belgian day-ahead market was ~24 TWh in 2015. The day-

ahead prices are basically proposed on a cost + margin approach.

In Belgium, the market price is mostly driven by gas assets which are called in the merit

order ranking. For very low demand, the pump storage hydro plants can be used to manage

flexibility instead of the gas plants (“Coo” power plant).

2.4.2.2. Intraday market

The principles of the Belgian intraday market are similar to Italy (see section 2.3.2.2).

However only the ARPs are active on this market in Belgium and exchanges can happen

until a very short time before the supply.

The system of ARP tends to optimize in real-time the use of the assets from a cost point of

view (welfare optimisation). This is not always the case in more rigid systems (like Italy)

where the plants have to follow their production schedule. Nevertheless there is also more

volatility on the Belgian Intraday market.

The total volume traded on this market was ~640 GWh in 2015.

2.4.2.3. Ancillary service market

The Belgian market organization is very similar to Italy (see section 2.3.2.3).

The main difference in Belgium is that all ancillary services are remunerated for the capacity

(“availability”), in addition to the generated energy (“activation”).

2.4.2.4. Forward market

The principle of the exchanges are similar to Italy.

The forward market for Belgium is the ICE Endex (“BE power baseload forwards”), which is

the leading energy exchange in continental Europe.

2.4.2.5. Capacity payment for planned shortage (“strategic reserve”)

The “strategic reserve” can be used by the TSO if the grid imbalance becomes very critical.

It can be activated in two circumstances:

1. Market disruption: if at the end of the day-ahead period of the European

Platform and after an ultimate procedure of auction/bidding the TSO fails to

obtain a balanced position (“uncoupled markets”);

2. Technical difficulties: the TSO anticipates major technical concerns;

In 2016, the Belgian Strategic reserve was fixed at 600 MW. An asset taking part to this

service has to be capable to start-up in a time delay of maximum 3 hours.

The selected units are contracted on a yearly basis following a bidding/auction process. The

remuneration of these assets takes two forms:

1. A capacity fee for the duration of the contracted period – 1 year

2. If started, a very interesting activation revenue corresponding to the highest

unbalance fee: ~3500-4500 €/MWh


In Belgium the Strategic Reserve has never been activated by the TSO so far. Units

proposed by the ARPs for the strategic reserve are most of the time at the end of their

lifetime or considered as no longer profitable on the other markets.

Extra considerations about the Belgian system

The system of ARPs resulted from the large market share of the former main utility on the

production at the time of the liberalisation of the market. It tends to give more “power” to the

producers which can control their balancing in a flexible way.

The ARPs, combined with the system of imbalance remuneration (see section 2.4.5), tend

to optimize the generation source with respect to a centralized dispatching (welfare

maximisation) but also causes more volatility on the imbalances.

Detailed information about the Ancillary Services

2.4.4.1. Primary Frequency Control

Description

Delivery of PFC is not (formally) mandatory but based on a bidding/auction market. In

Belgium, the TSO proposes four types of PFC contracts (or products) to the ARPs:

1. Symmetrical +/- 200 mHz: PFC starts at +/- 10 mHz; fully activated at +/- 200 mHz.

This profile fully matches with ENTSO-e requirements;

2. Symmetrical +/- 100 mHz: PFC starts at +/- 10 mHz; fully activated at +/- 100 mHz.

There is no technical difficulty for any thermal asset to follow such a profile;

3. Asymmetrical Down + 100 mHz: PFC starts at + 100 mHz; fully activated at + 200

mHz. This profile is interesting for assets running mainly at maximum load, no

derating on Pmax being needed. It corresponds to the typical load profile of Nuclear

Power Plants or CHPs;

4. Asymmetrical Up – 100 mHz: PFC starts at - 100 mHz; fully activated at -200 mHz.

Industrial clients capable to “buffer” their production are interested in such a profile

because the activation of the service (reduce/modulate their consumption) occurs

statistically rarely;

In addition to the first profile (1), the combination of the other profiles (2), (3), (4) allows the

TSO to build a global profile fully matching with ENTSO-e requirements. This original way

to proceed causes more competition between bidders. Bid prices in Belgium have been

decreasing in the past few years.


[mHz]


0 -200 -100 100 200 Frequency deviation

[mHz]


0 -200 -100 100 200 Frequency deviation

[mHz]


0-200 -100 100 200 Frequency deviation

[mHz]


0


SYMMETRICAL 100 mHz

ASYMMETRICAL UP

100 mHz

ASYMMETRICAL DOWN

100 mHz

= + +

Figure 28 - PFC products in Belgium


As for Italy, the total participation is fixed yearly by ENTSO-e. In 2016, Belgian participation

was fixed at 73 MW. In Belgium, plants installed in foreign countries can bid on this market

according to the following ratio:

up to 50 MW (symmetrical +/- 200 mHz) from a “Regional Procurement Platform”

regrouping Belgium, Germany, The Netherlands, Switzerland, Austria and France

(as from 2017);

the rest from assets located in Belgium;

The full PFC reserve should be provided within 30s and the plant should be able to deliver

it for minimum 15min.

Of course, Belgian ARPs can play on both local and regional platforms, meaning also the

possibility for them to sell PFC to the external countries part of this platform. Biddings are

made on a weekly basis. The PFC capacity is typically offered in combination with SFC

capacity (see hereunder). In addition, the ARPs should be prequalified by ELIA.

The PFC is automatically activated (based on frequency deviation) on the activated plants.

Remuneration

Remuneration is given on the capacity only, on a “pay-as-bid” basis. The energy is not

remunerated.

Penalties

Two types of penalties are applied by the TSO:

Availability penalties: if the amount of R1 sold doesn’t match with the theoretical

stacking of assets participating to the R1 (it can be the case if an asset becomes

unavailable and cannot be replaced by another)

Activation penalties: due if an ARP didn’t react in a proper way to frequency

“incidents”. The TSO performs post-incidents analysis (generally for frequency drops

> 100 mHz) and identifies those for which the contracted reserve was not correctly

provided (in term of amplitude and/or time delay). Penalties are fixed after (limited)

negotiations with the ARP.

2.4.4.2. Secondary Frequency Control

Description

In 2016, the total participation required for Belgium was fixed at 140 MW. This volume is

calculated by the TSO and validated by the regulator.

From a technical point of view:

Planned energy exchanges at the country borders are continuously compared with

real measurements installed on the interconnection points. An unbalancing signal (in

MW) is issued, called Area Control Error (ACE);

ELIA sends this signal to the ARPs in the limits they have contracted;

ARPs are free to dispatch this set point between their production units in the most

appropriate way (technical/economical);

A supplier must be able to fully cover the half R2 band (both upwards and

downwards) made available to ELIA, within maximum 7,5 minutes;


Figure 29. SFC activation requirements

In practice, the imbalances at a country level (deviation between scheduled supply /

demand) are detected by the TSOs on the cross-border flows. As Belgium is part of a large

synchronous area, frequency deviations do not give any indication on the national situation.

Remuneration

R2 is not (formally) mandatory but based on a weekly bidding/auction market. The following

principles are applicable:

Valid bid consists in offering a volume for the Service, being upward and/or

downward Secondary Frequency Control half band (R2), combined with a type of

Primary Control (R1);

The permitted number of capacity bids is unlimited. When participating, the supplier

will make its best efforts to introduce the largest number of combinations of

capacity bids possible (combinations of R1 and R2). Capacity bids will be at least

1MW and additional capacity offered in minimum increments of +/- 1 MW;

For the duration of the entire applicable delivery period, the provision of Secondary

Frequency Control capacity is portfolio based (not a specific power plant);

Once a capacity bid is awarded, the award decision is communicated to the

supplier by ELIA. ELIA will publish relevant, aggregated and anonymised

information regarding the awarded volumes and prices on its website;

A supplier has the possibility to transfer part or all of its R2 obligations to one or

several counterpart supplier(s), for instance in case of forced outage.

The remuneration of the service consists of a remuneration for the contracted R2 capacity

(reservation - availability) and a remuneration for the energy supply (upwards or downwards)

resulting from the activation of the service. The remuneration is based on a pay-as-bid

principle (weekly bid for the capacity, day-ahead bid for the energy).

As a general principle, the R2 selection (availability and activation) are based on the bids

merit order.

Penalties

As for R1, availability and activation penalties can be applied.

2.4.4.3. Tertiary Frequency Control

Description

The aim of the tertiary control is for the TSO to reconstitute its reserve once R1 and R2

have rebalanced supply and demand.

ACE [MW]

LOW LIMIT

HIGH LIMIT

0

ACTIVATION

7.5 min

7.5 min


In principle, the R3 volume has to cover the loss of the biggest unit of the country (in Belgium

~1000 MW – nuclear unit). Part of this reserve is supplied by the ARP owner of the asset

(N-1 reserve). The rest (~510 MW in 2016) is under the responsibility of the TSO.

Participants to the R3 have to be capable to produce the contracted load in a time delay of

15 minutes when they are requested to start by the TSO.

Downwards R3 participation exists but is not offered in practice (plants should operate above

their minimum load).

The TSO can also activate “Free Bids”. Free Bids have to be proposed by the ARPs on all

assets for the available power, without limitation of price (they can be very high). It is another

way (frequently used) for the TSO to reconstitute the Secondary Frequency reserve. The

TSO prefers to activate “Free Bids” (in practice, change of the load of a running asset) rather

than R3 capacity (in practice, it can mean the start-up of an expensive plant) as it is usually

cheaper and it keeps enough reserve in case of “incident”. Free Bids are only activated as

an alternative to R3 to reconstitute the R2 reserve (no active role of the TSO on the intraday

market).

Remuneration

The R3 service is based on a monthly bidding/auction market for the capacity.

The remuneration of the Service consists of a remuneration for the contracted R3

(availability), a remuneration for the energy requested resulting from the activation of the

service and a remuneration for the Start-Up of a Production Unit.

Energy is compensated based on Day-Ahead bids.

Participants are mainly power plants but aggregators or industrial clients with interruptible

contracts (ICH) can also take part to this service. For 2017, the awarded capacity of ICH is

200MW in Belgium (in addition to the ~510 MW mentioned here above).

As a general principle, the R3 selection (availability and activation) are based on the bids

merit order.

Penalties

The units can be penalized in case of “missing” MWs on the R3 reserve (priced at day-ahead

price) or in case the supplier used the reserve for its own use.

A plant can lose its qualification for Tertiary reserve if the plant fails 2 consecutive start-ups.

2.4.4.4. Black Start

Description

Five units located in five specific areas of production are needed to rebuild the grid in case

of blackout. Units performing a black start have to be capable to produce energy as soon

as possible on a “dead” network.

Remuneration

These units are contracted on a multiyear basis following a bidding/auction process. The

remuneration is based on the capacity.


Penalties

As these units must also be able to operate smoothly at any time, regular tests are carried

out. The owners are paid for the service and penalties are imposed if the tests are not

passed.

2.4.4.5. Reactive power supply

Description

A major responsibility of the TSO is to maintain the voltage within certain limits at any point

of the grid. The development of Renewable Energies makes this task increasingly sensitive

and difficult.

To increase flexibility, ELIA contracts from generators a positive and negative control band

for each unit (centralized control). If the system has a high load, ELIA asks for extra MVARs

to be generated.

Since reactive power cannot be transmitted over long distances, ELIA selects the units

participating in this service on their location.

Remuneration

The contract for this service provides two compensations:

1. a fixed rate to remunerate one-time expenses (IT implementation, technical

adaptations to the unit to expand the technical band)

2. an activation price remunerating the produced and absorbed reactive energy

providing a minimum level of MW injection by the concerned unit

Penalties

Penalties are applied if the automatic or centralized control are not well executed.

Production/absorption of reactive power is mandatory for the electricity producers.

Imbalance penalties

In case of imbalance between injections and offtakes

at a set of access points under the responsibility of an

ARP, the TSO:

applies penalties if the effect makes worse the

ACE signal

offers incentives if this imbalance helps the

TSO to maintain ACE balanced

From a practical point of view, it is not easy for an ARP to anticipate the TSO needs as it is

already difficult to assess accurately the balance within its scope of responsibility on-line

(metering on demand / clients side is not easy).

The unbalances can be solved by ARPs with their pump-storage hydro plants, when

available.

In the same time, ELIA concludes agreements for mutual assistance with other TSOs

allowing to exchange some volumes of energy in case of need. Prices are contractually fixed

on a yearly basis. The volume of this mutual assistance is continuously increasing, allowing

the TSO to reduce the incentives offered to the ARPs (judged more expensive).

ARP0

ACE

+-

+

-

ARP helps the TSO

Incentives

ARP helps the TSO

Incentives

ARP upsets the TSO

Penalties

ARP upsets the TSO

Penalties


Summary table and key highlights

Table 8. Belgian flexibility market summary table

Product Description Requirements Payment

Energy Day ahead and Intraday markets

Forward market

Balancing supply/demand

At ARP level (pooling)

Bid mechanism and “Pay-as-clear” market price

Ancillary - R1 Automatically activated

100% < 30s

Available for 15min

R1/R2 combination offers

At ARP level

Shared with border countries

Asymmetric offers accepted

Capacity: pay-as-bid (availability)

No energy payment when activated

Ancillary - R2 Set point from the TSO based on ACE

100% of ½ band < 7.5 min

Unlimited time

At ARP level

Upwards and downwards products



Ancillary - R3 Manually activated

Start-up time < 15 min

Only upwards product for plants

Industrial customers can participate for load shedding (ICH)



Strategic reserve

Selected plants – volume set by Minister of Energy

Start-up time < 3h

Contractual agreement on a yearly basis

Capacity: pay-as-bid

Energy: very high rate (~3500 - 4500 €/MWh)

Other key highlights:

All grid requirements and energy balancing are imposed at ARP level (pooling)

R3 accessible to industrial customers (ICH)

Regional prices (“copper plate”) are applicable most of the time, same price for

Belgium

Capacity remuneration for all ancillary services (but voltage control)

Volume of strategic reserve and other services: defined each year by the TSO and

approved by the regulator.

Black start and voltage control are remunerated.

Market evolution

In Belgium, the 96/92/EC Directive was translated in a national law in 1999 (29 April 1999

law on the organisation of the electricity market). The second and third liberalisation

directives were then respectively transposed in 2005 and 2012.

At the time of the liberalization, the market was highly concentrated in the hands of

Electrabel (now ENGIE Electrabel). Its market share was still ~65% for the generation and

~51% for the supply in 2014. Hence the company still keeps a strong position.

The Belgian TSO (ELIA) was created in 2001. It is on the stock market since 2005 and

ENGIE sold its last shares in the company in 2010.

The structure of the ancillary services contracts between the TSO and the suppliers was

defined at the time of the liberalisation of the market. The technical properties of the ancillary


services have not changed significantly since then. However, new products were introduced

on the market (like asymmetric participation) in order to increase competition as well as

international bids.

The energy exchange platforms did not exist at the beginning and they were put in place

progressively. The exchanges started with the communication of generation “programs” with

the TSO (often by phone, then fax). A national day-ahead exchange was then created,

followed by the intraday. The coupling with international energy exchange platforms was

also developed in parallel.

2.5. Comparison tables

A comparison of Belgium and Italy is provided together with the gap analysis with Chile

(section 5.2).


3. Impact of flexibility on thermal plants and technical

limitations

3.1. Conventional Power Plant Categories

The following types of power plants are considered in this study:

Rankine cycles (fuels: coal and fuel oil)

Combined cycle GTs (fuels: gas and diesel fuel oil)

Open cycle GTs (fuels: gas and diesel fuel oil)

Rankine Cycles (RC) are composed of a boiler (with its auxiliaries and FGT devices), an

extraction steam turbine (with its preheaters) and a condenser.

Figure 30: Rankine cycle - Process diagram [1]

Combined Cycle Gas Turbines (CCGT) are composed of one or several gas turbines (GT),

one or several heat recovery boilers (HRSG), a steam turbine (ST) and a condenser.

Figure 31: CCGT – Process Diagram ( [1] with modifications)


Open Cycle Gas Turbines (OCGT) are composed of a gas turbine only with its auxiliaries.

The exhaust gases are rejected directly to the atmosphere via a stack.

Figure 32: OCGT - Process diagram [1]

In the following sections, the applicability of the text to each technology will be specified.

The impact of the fuel or of some specific components will also be highlighted when

appropriate.

3.2. Impacts of the power system requirements on the technical

parameters of thermal plants

This section describes the impact of the energy market rules or ancillary services

requirements on the technical parameters of the power plants. It is a way to evaluate the

technical consequences on the power generation resulting from grid management choices.

Energy market

The implementation of an energy market tends to increase the flexibility of the power plants

in order to catch market opportunities. The technical impacts of a more competitive market

can be the following:

Increase Pmax to benefit from high spark spread in case of shortage on the market;

Incentive to shut down the units (including RES) when the spark spread (thermal

plants) or the prices (RES) are negative;

Incentive to improve the efficiency at all loads (and not just baseload) in order to

increase the spark spread (keeping a plant profitable or increasing the profit);

Reduce start-up / shut-down cost and time, to catch more opportunities (e.g. In UK,

CCGT plants stop and start twice a day, performing the so-called two shifting

operation – so they are able to capture very high spark spreads);


Figure 33: Catching more market opportunities: Examples of different typical modes of operation for power plants

At system level, an energy market does not always take into consideration the physical

constraints of the grid (congestions) and the risk of black-out (structural under-capacity).

Hence, the merchant market failures have to be compensated by regulated markets

(managed by the TSOs). In addition, energy markets require a trading structure (with related

costs).

RES integration

The integration of RES tends to shift the merit order due to the priority given to the RES

(nearly zero marginal cost).

Figure 34 - merit order illustration

Hence the penetration of the RES causes a decrease of the operating hours and load factors

of thermal plants. Figure 35 shows the evolution of the load factor of individual CCGT plants

in Europe with and without participation to the Ancillary Services (AS). The general trend is

a strong decrease of the load factor on a few years, excepted for the plants which are

enough flexible to participate to the ancillary services market.


Figure 35 - load factor evolution

The second effect of the increased RES capacity is a lower wholesale price on the market.

The consequence is that the profitability of some plants cannot be reached with energy

supply (they cannot compensate the fixed costs) and other sources of revenues are vital

(e.g.: ancillary services, strategic reserve, etc.). The need for additional revenues for

profitability has shown to be the main driver for the plants to improve their flexibility.

In many EU countries, a regulated capacity market was put in place to secure the electricity

supply (strategic reserve in Belgium, “essential plants” in Italy). However, the selection of

the plants is always based on a bid system and has to be approved by the European

Commission.

Capacity market

A capacity market may be required to guarantee the adequacy between the supply and the

demand on the mid – long term and mitigate the risk of black-out. However, it should reflect

as much as possible the real contribution of the power plants to the security of the system

in order to provide enough incentives for the maximization of the technical performances.

A capacity market on energy, regardless of the real contribution to the system stability, may

not give enough incentives to the plants to increase their flexibility.

Besides, granting a fixed feed-in tariff can push the plants to declare a Pmin higher than the

technical capability and/or give no incentive to decrease it.

Ancillary market

The introduction of a market for ancillaries with clear products gives incentives to the plants

to increase their technical performances in order to increase their profits.

In Europe this effect was emphasized by the overcapacity, as the revenues from the ancillary

market are often the only way for the plants to remain profitable. This is illustrated on Figure

36 for Italy (x-axis corresponds to different CCGTs and y-axis to the margins in €/MW when

considering only the variable costs) which shows that the contribution of the ancillary

services (“MB” and “MSD”) to the plants margins is very large (often >50% of the margin).

Some plants lose money on the Energy markets (negative margin on “MI” and “MGP”) but

can be profitable thanks to the ancillary services.


Figure 36 – Historical results on the Italian CCGTs in 2015 for each market. Y-axis represents the margin after discount of the variable costs, in €/MW. X-axis represents the different CCGT units.

Ancillary services are traded on “MB” and “MSD”. “MI” and “MGP” are the energy markets (cf. section 2.3.2). Horizontal dotted line corresponds to the average margin. [20]

The introduction of asymmetric services or international exchanges (if permitted) can

increase the competition between the suppliers.

Primary Frequency Control (R1)

The primary frequency control (PFC) should be delivered in a very short period of time

(typically 30s) and sustained for a reasonable time (typically 15 min). In addition, the very

fast reserve (VFR) should always be available for the power plant participating to the

frequency control.

The sensitivity of the load change to a change in frequency is defined by the droop. A lower

droop will cause much higher load changes (even for limited frequency changes) and

ultimately a higher “cycling” on the components (fatigue issues).

The maximum VFR is mainly limited by the allowed ramp rate (MW/min) for PFC (usually

higher than the standard ramp rate: typically 20MW on 30s for PFC ramp rate vs 10MW on

30s for standard GT ramp rate).

As the VFR should always be available when the plant participates to PFC, the power plant

output should be lower than Pmax (or higher than Pmin) when the frequency is at its nominal

value (see Figure 37). The difference (ΔPR1) can be higher or lower than VFR, depending

on the following:

- ΔPR1 can be decreased if an exceptional operating mode is allowed for PFC (Pmax

and Pmin exceptional). This is very dependent on the time to be sustained (e.g. 15

min)

- ΔPR1 may be required to increase if one of the components is too “slow” in order

to provide the power output change in compliance with VFR requirements (typically

HRSG+ST6, GT with lower ramp rate close to base load)

6 On a CCGT, the response of the ST is too slow for R1 requirements (unless ST participation with inlet valve throttling is implemented). Hence 10MW of reserve on CCGT would require 10MW de-rating on the GT, which means ~15 MW de-rating on the CCGT.


Figure 37 - Derating on Pmax (ΔPR1) or uprating on Pmin. ΔPR1 is the difference between “Pmax” and “Derating on Pmax” lines. Green band: possible range of power variation on de-rated Pmax due to

frequency variation (upwards / downwards).

ΔPR1 can have a major impact on the energy production (loss of opportunity at base load or

additional fuel use at low load) and plant efficiency, and hence a financial impact on the

plants.

Increasing the power output (during under frequency events) is typically more difficult than

decreasing it. Hence asymmetric frequency response can be a way to increase the number

of actors able to provide PFC and bring more competition to the market (if any).

From a TSO point of view, imposing PFC participation to all plants brings more reliability to

the system. However, it increases the overall system operating costs as the technical

impacts on the plants are high (i.a. de-rating). Hence VFR pooling (including sharing it with

foreign countries) can be considered when the grid interconnections are strong enough and

the amount of assets is large enough.

The PFC is fully automatic (based on frequency deviation) and does not require any specific

communication with the TSO for its activation. However, a signal is needed to switch on/off

the participation of the plant to the PFC. Additional signals can also be foreseen for an on-

line adaptation of the settings (droop, max frequency deviation, deadband).

The trend in Europe is to enable an on-line testing of the R1 capability (which requires

specific communication signals) for the TSO to check the capability of the plants to fulfil their

obligations.

Secondary Frequency Control (R2)

The Secondary Frequency Control (SFC) should be delivered in a short period of time (a

few minutes) and sustained for an unlimited time.

Limitations on the provision of SFC can be low ramp rates (technology related limitation) or

very high requirements on SFC regulation band delivery time (country-specific). On flexible

CCGTs and on OCGTs, the ramp rates are usually not the limitation of the extent of the half

bands unless the time for power delivery is short (e.g. Italy).

However, for many plants the maximum half bands are defined by the absolute turndown

(Pmax – Pmin). Hence, the main levers to extend the half bands are an increase of the Pmax

and/or a decrease of the Pmin.

Asymmetric SFC can increase the competition for the supply of SFC (more units able to

supply it).

As for the PFC, the SFC has an impact on the energy production as the load set point is

defined by the system operator.


Secondary Frequency Control is performed only on the selected units (based on the ancillary

capacity market). The activation of the service is then done when required (energy bid merit

order).

The SFC is requested based on an automatic external signal (set point) sent by the TSO or

another balancing entity. This signal is computed from the unbalances at the limits of the

Control Area (typically cross-border exchanges). Hence a specific communication signal

should be foreseen.

SFC is particularly important to compensate the unexpected/sudden power variation of RES.

Tertiary Frequency Control (R3)

The Tertiary Frequency Control should provide power in a time frame of typically 15 min to

reconstitute quickly the SFC. It is applicable to plants which are not connected to the grid

and should start-up (“cold reserve” or “offline”) or to plants in operation with available spare

capacity (“online”).

The main lever to provide R3 services is the optimization of the start-up time. In addition,

the plant operators can also optimize the stat-up fuel consumption to limit the costs.

Pooling effect

The pooling effect (as in Belgium) has an impact on the number of plants affected by the

PFC and SFC. The ARPs can select the plants in charge of the PFC/SFC management and

optimize the overall costs.

This means that most of the plants can operate at their Pmax / Pmin, without any provision for

PFC/SFC, or can even be shut down if this minimizes the costs (typically for the week-ends).

In some extreme cases, the turndown of a unit can be “artificially” extended by degrading its

efficiency and therefore decreasing its Pmin in a controlled way (Pmin exceptional). It allows

to concentrate the R1/R2 services on this unit and to realize the economy of another “must

run” unit.

Internationalization of the market

When the electrical interconnections are strong enough, the PFC can be distributed between

several Control Areas. In case of incident on one part of the grid, the frequency response is

shared between all Control Areas in the Synchronous Area.

The SFC is used to re-balance the planned exchanges between the Control Areas.

Black start

Black start implies specific requirements on the design of the power plant. It mainly consists

in the installation of a diesel generator able to restart the plant without external supply.

Penalty on imbalances

If TSO increases the penalty on imbalances, the plants are incentivized to implement the

following:

- Increased ramp rates to compensate quicker their imbalances;

- Increased online corrective actions:

o At asset level: correction of the MW setpoint to balance the ¼ h production

(as in Italy);


o At pool level: corrective actions through hydro storage units (as in Belgium);

- Improved calculation of Pmax and Pmin (correction curves taking into account

atmospheric and process conditions);

- Increased reliability:

o Improved control loops to avoid mismatches and/or trips (i.e. “Model based

control” to anticipate plant reaction);

o Increased level of automation ensuring the repeatability of the start-ups and

avoiding human mistakes;

o Improved training of the operators;

o Improved Root Cause Analysis and troubleshooting, and perform immediate

corrective action in case of incident/trip;

- On a longer term, power plant performance follow-up procedures allowing to identify

deviations and take corrective actions;

Voltage control

Voltage control has a limited impact on the power plants but it requires specific control loops.

Very high reactive power demands can create some limitations on the supplied active power

(P-Q diagram).

Since reactive power cannot be transmitted over long distances, the units participating in

this service are selected based on their location.

3.3. Technical limitations for each category (including emissions)

This section details the main technical limitations faced by the plants to improve their

flexibility.

Most units are originally designed for base load operation (efficiency is also optimized for

baseload). This leaves some potential margins towards more flexible thermal units. For

example, the number of opportunities that involve low CAPEX expenditures is limited for

Pmax (baseload). But the potential for Pmin reduction is quite attractive.

Apart from the technical limits of the unit, power plants may not allow or limit flexible

operation for other reasons, such as contractual motives (LTSAs, guarantee of the

OEM) or asset management strategies. Even if these reasons may be justified, they

are not detailed in this study.

Rankine cycles

For Pmax increase, CCGTs and Rankine cycles share most technical limitations, mainly

related to the water-steam cycle. These limitations are described hereafter:

1. Maximum steam temperature and pressure within the boiler and/or

admitted at the steam turbine: Usually, design values are reached at

current Pmax,


2. Steam flow limitation on the steam turbine: the design of the turbine

does not allow to handle the additional steam flow at increased Pmax,

3. Feedwater pump capacity: As a Pmax increase, usually means higher

water flow rate from the feedwater tank,

4. Contractual limitation: the transmission system might reach the

maximum energy transport capacity. TSO will therefore waive the Pmax

increase potential as the additional energy could not be pushed onto the

grid.

Figure 38: Pmax evolution of a subcritical Rankine cycle in Poland

Regarding Pmin reduction, the following technical limitations apply:

1. Circulation in the water-steam cycle: This needs to be maintained to

sufficient levels to ensure that the quality of the live steam (i.e. minimum

superheating of +50°C) will be kept acceptable. Furthermore:

a. The SCR7 inlet temperature is kept high enough to avoid the

formation of ammonium salts in the catalysts and the preheaters,

which can lead to fouling and corrosion

b. The inlet temperature of the air preheaters is kept sufficiently

high to avoid the formation of highly corrosive sulfuric acid in the

preheaters [26], [27]

2. Minimum steam flow through the turbine: Steam flow needs to be kept

above a certain limit in order not to move upstream the Phase Transition

Zone in the LP turbine (i.e. where steam starts to condense). Also, to

avoid temperature increase in the turbine. Detrimental operational

conditions leading to steaming and flashing should be prevented as well

to avoid erosion in the tubes and valves.

3. Fluttering: At low load, last stage(s) steam turbine blades may

experience liquid-droplet erosion issue and dynamic excitation so-called

(fluttering). These phenomena have been responsible for blade failures

7 Selective Catalyst Reduction (SCR) systems are flue gas treatment devices to absorb the NOx emissions


and design modifications are necessary for sustained operation under

these conditions.

4. Coal Mills: the general consensus is that Pmin can often be reduced up to

70-80% turndown, depending on the design of the installation. The load

reduction requires to switch-off some burners and coal mills (up to two

mills in operation in general, sometimes one mill for new design) but not

beyond the point where gas or diesel injection is required to sustain the

flame. The minimum capacity of the coal mills in operation sets the Pmin

of the unit. In some case the speed of the induced- and forced-draft fan

might be a limiting factor as well.

Figure 39: Pmin evolution of a subcritical Rankine cycle in Germany

Rankine cycles have different technical limitations on ramp rates. The main limitations are

detailed below:

1. Benson-type, forced circulation boilers offer more flexibility than

natural circulation boiler since drum-related limitations, especially on

temperature gradients, are not applicable,

2. Coals mills with indirect combustion, i.e. with storage capabilities,

respond faster than coals mills with direct combustion as increased

pulverized coal demand can be rapidly supplied from the storage.

However, the response is generally delayed by 1.5-minute dead time

which detrimentally affects the ramp rate initially. The

responsiveness of the coal mills is moreover very complex to predict

as it depends on many other process parameters.

3. The burner configuration, i.e. number and position of in-service

burners,


Figure 40: Maximum ramp rates evolution of a subcritical Rankine cycle in Germany

Figure 41: Evolution of a warm start-up time (Rankine in Poland) and fuel consumption (Rankine in Germany)

Whereas there are no technical limitations related to minimum up time, some exist for

minimum down time.

1. Stress in the boiler parts. To avoid stressing the boiler parts, especially headers

and tube arrays, natural cooling during a design-specific duration is advised and

can preclude fast restart of the unit. Some plants have tried to shorten this minimum

down time by accelerated cooling, but they came back to natural cooling after

structural integrity issue on the boiler.

2. Water chemistry. Water steam chemistry treatments during the shutdown

procedure may require some time and, as such, be a limitation for the minimum

down time.

CCGTs

Whether the combined cycle is based on a heavy-duty or aeroderivative gas turbine, one

can identify some technical limitations towards flexibility improvement of such plants.

Regarding Pmax increase, some technical limitations can be observed in the process. The

most important ones are listed hereafter:

1. Flame temperature on the gas turbine as the hot gas path components

operate under conditions of high stress and temperature, nearing material

resistance capabilities. Different ranges of flame temperature applies to


the GT technologies available on the market: 1020 to 1100°C for E-class,

1230 to 1360°C for F-class and +1400°C for H-class.

2. NOx limitations: the higher the flame temperature, the faster the NOx

formation.

3. Maximum steam temperature and pressure within the heat recovery

steam generator and/or the steam turbine. The maximum temperature

and/or pressure8 allowed by design can be reached.

4. Steam flow limitation or power limitation on the steam turbine, which

actually means that the steam turbine might become undersized to handle

the steam flow as Pmax is increased,

5. Feedwater pump capacity as a Pmax increase practically means higher

water flow rate from the feedwater tank or from the LP drum to the HP

and IP drum,

6. Reactive power that is demanded by the grid can impose some

limitations on the active power, hence forcing Pmax down,

7. The cooling capacity of the generator, which relates to the cooling

water temperature, can become the limiting factor

8. Contractual limitation on fuel capacity or gradients. For instance, if

both the power plant and residential heating use the same gas lines, local

authority may impose a maximum off-take to the plant to avoid

disturbance or even shortage at residential level. In addition, in case of

high gas consumption, the pressure on the gas grid can drop below the

minimum pressure required by the GT (defined by the combustion

chamber pressure) and force a power de-rating (up to a certain limit).

9. Contractual limitations as the transmission system might reach the

maximum energy transport capacity. TSO will therefore waive the Pmax

increase potential as the additional energy could not be pushed onto the

grid.

10. Special constraints when using liquid fuel in the GT: The exhaust

gases temperature and flow are increased due to the higher steam

content following water injection. Any further increase of temperature or

flow might not be possible if design limits are already reached on the

HRSG, e.g. temperature and pressure conditions in the HP drum. Water

injection might be also limited by the maximum flow the demin water plant

can deliver.

11. Hot ambient conditions: Pmax increase potential can be limited if no inlet

air cooling system is installed. Depending on the inlet cooling system, the

lifetime of the first compressor blade rows can be impacted due to liquid

droplet erosion.

8 In sliding pressure mode, the pressure at ST inlet is almost proportional to the steam flow. Hence the maximum pressure (on ST or HRSG) is actually a limitation on the steam flow.


12. Commercial limitations such as imbalance issues that can occur at the

end of a load variation due to ramp rate limitation, because Pmax is defined

in steady state conditions.

Figure 42 provides an example of the evolution of the Pmax on a F-class CCGT in Europe

thanks to a GT upgrade.

Figure 42 - Pmax evolution on a F-class CCGT

Pmin reduction in CCGTs technical limitations are outlined below:

1. CO limitations: As long as the flame remains in premix mode, the

lower the flame temperature, the faster the CO formation.

2. NOx limitations: Also applicable as high-temperature pilot flame is

required at low load to maintain the stability of the flame9. Compliance

with emissions is also the limiting factor when Pmin is reduced by

controlled degradation of the efficiency.

3. Low steam pressure on the HRSG, which can cause erosion in the

lines and flashing in the valves (sudden evaporation) due to

excessive steam velocity.

4. Temperature increase in the steam turbine due to a too low steam

flow (hence lower expansion ratio),

5. With Air Cooled Condenser systems, the cooling capacity might

become oversized. This can lead to the formation of ice inside the

lines while operating at low ambient temperatures,

6. Compressor instabilities may be triggered. This can lead to

catastrophic blade failures,

7. Combustion instabilities: When the load is decreased, the

operating point of the machine can move closer to CO limit and to

frequencies where combustion instabilities occur. The actual tuning

9 In premix mode, the fuel gas and air are premixed before the burner. This combustion mode generates less NOx emissions but is less stable. In a pilot flame, the premix is very low or even zero (pure fuel), which gives a much more stable combustion but generates higher NOx emissions.


and physical limits of the gas turbine can prevent further reduction of

Pmin.

Figure 43 - combustion stability area and instability frequencies. “TTRF” corresponds to the turbine inlet temperature. “Split” corresponds to the gas distribution between premix and pilot flame.

8. Gas turbines are basically tuned for baseload operation. Some

types of gas turbines, e.g. SGT5-2000E, feature asymmetrical

thermocouples distribution in the exhaust duct to measure the

exhaust temperature in the hot spots. However, at lower load, the hot

spots change position and can be out of reach of the thermocouples.

Error on measurements of the turbine outlet temperature can lead to

regulation issue.

9. Fluttering: At low load, last stage(s) steam turbine blades may

experience liquid-droplet erosion issue and dynamic excitation so-

called (fluttering). These phenomena have been responsible for

blade failures and design modifications are necessary for sustained

operation under these conditions.

Figure 44 provides an example of the evolution of the Pmin on an F-class CCGT. Most

improvements were reached by implementing a better combustion tuning and a control loop

optimization.

Figure 44 - Pmin evolution on a F-class CCGT


Ramp rates are key contributors towards increasing the flexibility of the power plants. They

allow a closer tracking of the load variation. During start-ups, they contribute to the reduction

of the start-up time. Ramp rates play an active role when providing SFC. However,

increasing ramp rates have some process limitations, including but not limited to:

1. Temperature and pressure increase in the HRSG, especially in the

drums and the array of tubes exposed to the hottest exhaust gases,

which could be irreversibly damaged by too high rates. The wall

thickness of the HP drum plays a predominant role in the limitation of

the ramp rates. The pressurization ramps in the HRSG can be

controlled and optimized with the use of a stress evaluator model.

2. The quality of the control loops which need to be robust against

perturbations and deliver a fast response. For instance, increased

ramp rates were achieved by ELL intervention, manly solving

instabilities of control loops dedicated to steam turbine control valves,

drum level oscillations or attemperation in the HRSG.

3. The availability of advanced controller libraries to program

advanced control loops (i.e. Model Based Control).

4. Stress induced in the rotor of the steam turbine by the thermal

transient in addition to the centrifugal force. In this case, the

maximum ramp rates are controlled by stress calculator/stress

computer.

Figure 45 provides an example of the evolution of the ramp rate on a F-class CCGT thanks

to a control loop optimization and the release of OEM limitations.

Figure 45 - ramp rate evolution of a F-class CCGT

At part load, the efficiency of both the gas and steam turbine is lower. Nevertheless, it can

be improved in some ways. Some examples are turning off auxiliaries not needed at part

load, installing Variable Speed Drives (VSD) or by optimizing the set point of the

backpressure in the condenser.

Whatever the ramp rate of the unit, the start-up time is primarily impacted by the preparation

time which mainly consists of:


Conditioning the gland steam, if gland steam is not immediately available from the

HRSG, or an auxiliary boiler

Creating the vacuum in the condenser, if vacuum was not kept during the

downtime

Apart from this, during the GT acceleration phase, the start-up time is also impacted by the

purging time, which vary from a plant to another (volume of the HRSG), but also from an

OEM to another (compressor flow). The degree of automation of the start-up sequences

plays an important role in the total start-up time.

Figure 46 provides an example of evolution of the start-up time and fuel consumption on an

F-class CCGT thanks to the optimization of the start-up strategy, sequence and control

loops.

Figure 46 - Start-up time (<12h shut down) and fuel consumption for a F-class CCGT

Whereas there are no technical limitations related to minimum up time, some exist for

minimum down time.

1. Thermo-mechanical constraint of the HRSG. The heavy, thick-walled parts from

the HRSG and, eventually, of the steam turbine, are subject to high thermo-

mechanical constraints during a shutdown of the unit. A minimum time can be

necessary to let these critical parts cool down properly and to avoid to affect their

integrity with time.

2. Thermo-mechanical constraint of the GT. In some cases, the rotor of the gas

turbine may be a limiting factor as well.

3. Water chemistry. In some cases reported to ELL, water steam chemistry

treatments during the shutdown procedure can take some time and impact the

minimum down time of the unit.

Frequency control, both PFC and SFC, have technical limitations. For PFC, the delivery of

VFR has a commercial benefit but also technical drawbacks, e.g. risk of combustion

instabilities on GT burners and excessive temperature and pressure gradient on the water-

steam cycle upon reduction of the droop. For SFC, depending on the plant, either the ramp

rates or the turndown (hence Pmax and Pmin) can become the limiting factor, each with their

own technical limitations already developed above.

Figure 47 provides the evolution of the PFC and SFC reserves on two different F-class

CCGTs respectively, thanks to the decrease of the allowable GT droop and the increase of

the turndown.


Figure 47 - PFC and SFC reserve evolution on 2 F-class CCGT

OCGTs

Operation in open cycle offers a high level of flexibility as the HRSG, BoP and steam turbine

and related technical limitations are not involved, but it is done at the expenses of efficiency

and moreover cannot be necessarily sustained for a long time due to emissions.

Pmax increase is limited by similar factors as for CCGT:

1. Flame temperature on the gas turbine as the hot gas path

components operate under conditions of stress and temperature

nearing material resistance capabilities whilst still preserving a

sufficient lifetime

2. NOx limitations: the higher the flame temperature, the faster the

NOx formation,

3. Reactive power demanded by the grid can impose some limitations

on the active power, hence forcing Pmax down,

4. Contractual limitation on fuel capacity or gradients imposing a

maximum gas off-take to the plant to avoid disturbance or even

shortage at residential level.

5. Contractual limitation since transmission system might reach the

maximum energy transport capacity. TSO will therefore waive the

Pmax increase potential as the additional energy could not be

pushed onto the grid.

The following technical limitations apply to Pmin reduction for OCGT:

1. CO limitations: As long as the flame remains in premix mode, the

lower the flame temperature, the faster the CO formation.

2. NOx limitations: Also applicable as high-temperature pilot flame is

required at low load to maintain the stability of the flame10.

Compliance with emissions is also the limiting factor when Pmin is

reduced by controlled degradation of the efficiency.

3. Compressor instabilities may be triggered and can lead to

catastrophic blade failures.

4. Combustion instabilities (see CCGT section).

10 In premix mode, the fuel gas and air are premixed before the burner. This combustion mode generates less NOx emissions but is less stable. In a pilot flame, the premix is very low or even zero (pure fuel), which gives a much more stable combustion but generates higher NOx emissions.


For ramp rates, some technical limitations still remain:

1. Expansion and thermal stresses on the heavier components of the

gas turbine (e.g. casing). This is less a problem for OCGT running

aeroderivative gas turbine because of their lighter, thin-walled

construction.

2. Temperature and thermal stresses induced by the electrical

loading in the copper core of the rotor and stator of the generators.

This limitation also relates to the cooling capacity of the generator.

Minimum up and down time are not usual for OCGTs. Sometime, and for specific GT

manufacturers, a minimum down time after shutdown is set to avoid excessive thermo-

mechanical constraint on the GT.

Emissions

European regulations (see section 2.2.4) define threshold values for the emissions which

have to be transposed into national and even regional laws in order to deliver a local permit

to the power plants.

Different emissions directives exist in Europe, each with own specific rules and exceptions,

which then need to be aligned and transposed into limits by the local authorities. Local limits

are generally more stringent than the generic limits defined at European level.

The emission limits are defined as hourly, daily, monthly and yearly compliance. Table 9

shows the percentile 10, 50 and 90 of daily-compliance emission limits for a representative

fleet of thermal assets in Europe, for respectively Rankine cycles, CCGTs and OCGTs.

Table 9: Emission limits for a representative fleet of thermal assets in Europe Daily compliance P10, P50 and P90 in normalized ambient conditions and O2 content

mg/Nm³

Rankine cycles - coal and biomass

6% O2

CCGT - gas 15% O2

OCGT - gas 15% O2

P10 P50 P90 P10 P50 P90 P10 P50 P90

SO2 50 277 400 10 11.6 120 - - -

NOx 100 200 400 41 50 93 33 50 75

CO 50 100 198 53 100 100 29 92.5 100

PM 10 25 56 2 5 8 - - -

At the date of this report, not all the environmental permits received by ELL comply

with the regulatory limits of the IE-D (in red in Table 9). This may be due to the delay

between the date of the entry into force of the IE-D, and the date on which the

environmental permits will be re-written.

The transposition of the emission limits by local authorities on a case-by-case basis can lead

to limitations for the flexibility potential of power plants. Some examples are given below for

CCGTs and OCGTs. When dealing with emissions, one have to pay particular attention to

the unit in which emission limits are expressed. Indeed, limits expressed as concentration

are more stringent than volume. A given volume on yearly-basis can be respected with large

fluctuations in concentration over the year.

- The maximum CO concentration is not always applicable to some plants, but can

impose some limitations on the Pmin of other plants.


- Limitation on emitted volumes can impact the allowable number of start-ups and the

operation time at low load. As example, the total volume of NOx produced during start-

up must be below 7% of total yearly volume of NOx, which leads to restrictions on the

number of starts. Plants can work around this type of restrictions by adopting start-up

sequences reducing the number of NOx produced during start-up (e.g. start-up as

OCGT) but ultimately resulting in a bad emission - produced power ratio up to

reaching combined cycle mode.

- When the plant is operated below a certain load (e.g. 60-70% of Pmax), the NOx and

CO emission limits can be multiplied by a factor (e.g. x2),

- For plants operated less than a given number of hours per year, either no NOx

emission limits apply (e.g. <150 hours/year) or the NOx emission limits is increased

to a certain level, e.g. the NOx concentration limit of 50 mg/Nm³ above 70% load

becomes 150 mg/Nm³ for whatever load if the plant is operated less than 1500

hours/year as per moving average calculated over a period of 5 years.

- Specifically for Rankine cycles,

o Emissions limits might be exceeded if the DeNOx temperature is too low

(e.g. during start-up or at Pmin). Emissions are normally not a concern when

the plant operates at baseload and if the flue gas treatment devices are

operating correctly,

o Rankine cycles without flue gas treatment may face some difficulties to

control the emissions in case of load variation,

For OCGT and CCGT, when fuel oil is burnt, the emission limits are modified. For example,

NOx limits can be doubled but the CO emission limit value remains the same as for natural

gas, but only applies to a smaller power range, e.g. from 75 to 100% instead of 60 to 100%.

The ambient temperature can also affect the minimum load where to be compliant with the

emission limits. For example, below 15°C, the lower limit of the emission compliant GT load

range can be increased up to 80% for fuel oil and from 50 to 56% for natural gas. For other

plants, the GT load range is the same for both natural gas and fuel oil and changes with the

temperature as well, i.e. 50-100% below 37°C and 62-100% above.

The aforementioned limitations show how the regulatory context as applied in Europe can

lead to large discrepancies on the emission allowance of two identical units and is often

subject to interpretation and workaround the imposed limits. In most cases, one can state

that emissions were generally not a limiting factor for flexibility.

3.4. Performance benchmark for each category

In this part, ELL selected a representative fleet of thermal assets in Europe, and looked at

the operational parameters of each of them. Some characteristics of the fleet are mentioned

in Table 10.

Table 10: Representative fleet of thermal assets in Europe, some characteristics

Category # units

Rankine Cycle 16


CCGT 26

OCGT 5

Country of origin 11

The performances of the different thermal assets chosen by ELL are presented for each

category of plants in Table 11 to Table 13. 10th percentile (P10), 50th percentile (P50) and

90th percentile (P90) are calculated to illustrate the average and the spread in terms of

performance in each power plant category.

Figure 48: Definition of P10, P50 and P90

3.4.1.1. Rankine cycles

Since both subcritical and ultra-supercritical (USC) boilers are currently installed in Europe,

a benchmark is provided with USC (Table 11) and without the USC units (Table 12).

The performance benchmark with the USC units is more representative of the current

situation in Europe, while the performance benchmark without USC is found more

comparable with the situation in Chile, where only subcritical units are installed.

Table 11 : benchmarking of Rankine power plant performances, USC included

10th percentile 50th percentile 90th percentile

Pmin (MW) 109 120 191

Pmax (MW) 207 224 661

Relative turndown (%) 37.26 46.99 76.49

Ramp rate (MW/min) 2 2 17

Ramp rate (% Pmax/min) 0.74 0.90 3.00

Start-up times for following downtime (min)

<8 hours 90 151 151

8-32 hours 204 225 326

32-72 hours 354 480 522

>72 hours - 660 -

Minimum uptime (min) 270 720 720

Minimum downtime (min) 90 120 360


Table 12 : benchmarking of Rankine power plant performances, USC excluded


Pmin (MW) 105 119 195

Pmax (MW) 206 223 435



Ramp rate (% Pmax/min)

0.70 0.90 1.03


<8 hours 150 151 151

8-32 hours 198 225 320

32-72 hours 324 420 516

>72 hours - - -

Minimum uptime (min) 318 720 720

Minimum downtime (min)

120 120 360

3.4.1.2. CCGTs

For CCGT, both 1+1 (1 GT + 1 ST) and 2+1 (2 GT + 1 ST) configurations are

installed in Europe. For a coherent benchmark between 1+1 and 2+1 CCGTs, the

performance of the 2+1 installations are compared in 1+1 mode only.

Table 13 : Benchmarking of CCGT power plant performances (1+1 configuration)


Pmin (MW) 118 163 210

Pmax (MW) 338 390 438



Ramp rate (% Pmax/min) 2.89 5.10 7.29


<12 hours 41 66 85

12-32 hours 58 80 116

32-56 hours 76 99 141

56-72 hours 87 113 153

>72 hours 103 199 279

Minimum up time (h) 0 1 10

Minimum downtime time (h) 0 3 6

Black start capacity 2 out of 26 plants

Very Fast Reserve (MW) 11 25 36

SFC maximum power (MW) 20 78 150


3.4.1.3. OCGTs

Table 14 : performance of OCGT power plant


Pmin (MW) - 40 -

Pmax (MW) 22 75 130


Ramp rate (% Pmax/min) 13 36 75

Start-up time up to Pmax (min) - 30 -

For OCGTs, ELL did not find representative values for minimum up and down times.


4. Analysis of the current situation in Chile

4.1. Overview of Chilean Electric Systems

Chile’s geographical characteristics make it a very particular environment to the

development of electric infrastructure. Chile is in the middle of two important geographical

features: the Pacific Ocean and the Andes mountain range, one of the tallest and longest

ranges in the world. Both are separated by an average of 177 km, opposing to the near

4.300 km long of the country, which accounts for an approximate land area of ~743 800

km2.

Chile‘s wide spatial distribution has allowed to count with a privileged position in terms of

renewable energy resources. While the extreme north highlights because of the dry climate

and extremely high irradiance conditions, the south, in contrast, has exceptional water and

biomass resources. Geographical distribution of the resources and people’s distribution over

the territory have been key factors and they have highly conditioned the development of the

electricity grids. Whereas the resources are distributed in the north and the south of the

country, consumptions centres are mainly located in the central zone of Chile, which

imposes some constraints in the planning and development of the electricity infrastructure.

Chilean electricity market is structured in two main grids: The SIC and SING (along with two

medium isolated systems - Aysen and Magallanes - and two small isolated systems - Los

Lagos and Isla de Pascua- which are out of the scope of this report). The origin of both

systems was the interconnection of several smaller subsystems which aimed at supplying

cities and big industries (particularly true for the mining industry in the SING). The final

coordinated operation of each system was achieved in 1968 for SIC and in 1993 for SING.

SIC is characterized for being a hydrothermal system (40% Hydro, 45% Thermal, 15%

RES), which concentrates near a 75% of Chile’s electricity demand (estimated in 70 TWh

for 2017) and a 92% of Chilean population (whose residential consumption is estimated in

aprox 34 TWh). The grid has a very extensive length, but is barely meshed, with a total

length of transmission lines of 20 058 km (in Oct-2015). As a reference, the maximum hourly

average demand reached 7 800 MW in 2016.

On the other hand, the SING is mainly an industrial system that has developed around the

mining sector. The SING has an eminently thermal composition (90% of its installed capacity

is thermal) and concentrates 6% of total Chilean population. The mining sector is the major

consumer of energy in the SING, accounting for 90% of the energy demand. The industrial

sector with a flat load profile and 24/7 energy requirements have relied mainly in thermal

power plants as the cornerstones of their supply. The intrinsic development of the grid has

resulted in a transmission system with the main power plants in the coastline (for raw

materials reception and refrigeration needs), meanwhile mining consumptions are located

towards inlands, close to the mines and industries. As a reference, the maximum hourly

average demand reached near 2 400 MW in 2016, which were produced along the 8 391

km of transmission lines that compose the grid (according Oct-2015 information).

Nowadays, Chile is not electrically interconnected with any neighbor, with the exception of

a low capacity (770 MVA) to Argentina (Sistema Argentino de Interconexión - SADI), at the

SING. This interconnection line was initially foreseen to provide energy from a combined

cycle located in Argentina to the SING, making profit of the economical Argentinian gas.


However, SADI’s undercapacity has reversed the situation and since 2015 the owner of the

line has authorization to export 200 MW from Chile to Argentina has been provided. In any

case, the interconnection helps stabilizing the frequency and provides a bigger inertia and

primary reserve in case of contingencies.

Each of the electric systems has its own independent system operator (ISO), which plays

coordinates the operation of the grid. ISO’s do not own any generation, transmission nor

distribution assets. In Chile, ISOs have been called the CDECs, whose acronym stands for

Centro de Despacho Económico de Carga (or Economic Load Dispatch Center). In the case

of SIC this responsibility relapse in CDEC-SIC, while in SING it relapses in CDEC-SING. At

the beginning of 2017, both CDECs were merged, creating the CEN (Independent

Coordinator of the National Electric System – SEN), in anticipation of the merging of the

systems which is expected to be carried out between 2018 – 2020.

According December statistics, available in both CDECs sites, the installed capacity in each

system is of 17 GW in the SIC, and of 5.5 GW in the SING, with the following breakdown:

Production Type – North CL (SING)

2016

[MW]

Coal 2650

Cogeneration 18

Fossil Oil 326

Hydro Run-of-the-river 11

Natural Gas 1942

Solar PV 346

Wind Onshore 202

Total SING Grand capacity 5495

Production Type – Central CL (SIC)

2016

[MW]

Biogas 57

Biomass 426

Coal 2571

Fossil Oil 2670

Hydro Run-of-the-river 2576

Hydro Water Reservoir 4046

Natural Gas 2526

Solar PV 1192

Wind Onshore 1087

Total SIC Grand capacity 17152

SING –

5495 MW

SIC –

17152 MW

Other isolated

systems –

188 MW

Figure 49: Breakdown of installed capacity by technology - SIC and SING (source: CDEC-SIC and CDEC-SING website)


4.2. Market Organization

Chilean electricity activities are structured among three main sectors: Generation,

Transmission and Distribution and they are all held by private companies, the State being

an entity with a regulatory, prosecutorial and subsidiary role. While generation is

characterized by being an open access sector (liberalized) with the possibility to any

company to enter the market, transmission and distribution are regulated because of their

natural monopoly characteristic. Under current Chilean regulation, the figure of the

Supplier/Buyer does not exist, taking that role the actors of the generation and distribution

segment. The main regulatory framework of the electric sector is provided by the DFL No.

4, “General Law of Electric Services”, meanwhile technical framework is specified in the grid

code or NTSyCS (Acronym for “Technical Standards of Safety and Quality of Service”, in

spanish).

Chilean electricity market is organized in two main markets: the wholesale market (physical/

spot market) with a pool structure, whose coordination is in charge of the CDECs, and a

financial market, where generators carry out supply contracts with clients (big consumers,

distribution companies or other generators) for a certain period of time (Figure 50).

Figure 50. Chilean electricity market organization

Products involved in Chilean electric market comprises two main products: Energy and

Capacity. Ancillary services does not represent a tradable product, but their provision is

mandatory and coordinated by the CDECs. In fact, under the current regulation, generation

companies do not consider the provision of Ancillary Services as a source of revenues or

as part of their core business.

The CDEC is the entity in charge of carrying the central dispatch of the generators pool,

ensuring to achieve the minimum economical technical operation and secure operation,

among others. The Chilean electricity market is structured as follows:

4.2.1.1. Spot Market

In the spot market, central dispatch is carried out by the CDEC and participation is

mandatory. Under the central dispatch scheme, generators are required to declare their

true variable costs (power plants can be audited), and the ISO balances the offer and the

demand in the spot market, setting the system’s marginal cost equal to the highest variable

cost that matches the offer and the load. Marginal cost is calculated for each node of the

system.

The pricing scheme in the Chilean electricity market, includes an energy component

calculated as explained above, and a capacity payment for all the plants in the system,

proportional to their contribution in system’s adequacy. The price at which capacity is paid,

is determined by a study done every 4 years by the regulator (CNE). As of 2017, the capacity

Chilean Electricity Market

Pool Market

(Spot Market)

Financial Market

(Bilaterial Contracts)


price is set every six months, as the cost of the optimal capacity expansion through a

calculation called “nodal capacity price”. This pricing scheme, named peak load pricing,

ensures (in theory) that with an energy payment and a capacity payment, the investments

and operation costs will be fully recovered by plant owners in systems with the offer adapted

to the demand. Both payment mechanisms, energy and capacity, are balanced by the

CDECs. The CDECs also manage other payments derived from the operation of the system

such as ancillary services payments (compensations), transmission capacity payments,

among other.

The spot market operation is executed according to two schedules: the weekly schedule

(medium term) and the daily schedule (short term). The CDEC solves the optimization

problem that defines the schedule (pre-dispatch) of all the generation units of the system

taking into account system constraints such as hydrology, availability of the power plants &

transmission lines, fuel availability, etc. Weekly schedules are based in long-term economic

optimizations of the system in order to estimate the future cost of water (for reservoir hydro

power plants). Companies involved in the process (mainly generators) are responsible for

providing true information about their infrastructure and foreseen conditions, which can be

audited by the ISO.

The ISO, sorts the pool of generators according to their variable cost, defining a merit order

of the power plants to supply the demand. From this procedure, a priority list of the power

plants is obtained for each day together with a summary of the operation of the reservoirs

and thermal power plants of the system. Daily schedule is developed each business day, in

order to adapt the pre-dispatch to foreseen conditions for the next business day (e.g.

weather forecast, demand deviations, affluent flows, operational constraints, contingencies,

etc.). After checking all the information, CDEC defines the final operating policies of the

system.

The real-time operation of the system is carried out by a specific department of the CDEC,

the Dispatch and Control Center (CDC), which follows and coordinates the real-time

operation of the system. CDC communicates with a Control Center of each coordinated

company, issuing instructions on how to operate their power plants.

4.2.1.2. Financial Market

Generators can be participant of a financial energy market, where supply contracts are freely

agreed between the parties (bilateral agreements). The existence of the financial market

allows the generators to accommodate their commitments (energy contracts) within the

economic operation determined by the CDEC. Commitments (financial market) and real

operation (centralized dispatching) are then balanced. Under this scheme, a generator

whose produced energy is higher than its commitments or withdrawals (Surplus situation) is

going to receive payments from other generators whose produced energy is less than its

withdrawals (Deficit situation).

Supply contracts are confidential, although the involved demand and the supply node must

be informed to CDEC to program the operation (Demand estimation). Main clauses of the

contracts comprises the agreed quantity and the transaction price of the product (energy,

capacity). Measurements are typically carried out on an hourly basis.

Generators can agree supply contracts with distribution companies through public supply

tenders or with big consumers (called “free clients”) through private contracts/tenders.


It is responsibility of the CDEC to calculate the payments between generators, due the

energy injection and withdrawals of their contracts they have carried out. For example, if a

generator needs 100 MWh to satisfy a client’s demand it has contract with, and it doesn’t

operate (because of the nature of centralized dispatching), it will require to purchase those

100 MWh from the wholesale market (at spot price).

4.3. Regulatory framework for Ancillary Services

Even though the first formal distinction between the concepts of adequacy and security of

the system was made in 2004 (Law 19.940), Chilean law has recently included ancillary

services in the regulation.

Adequacy is defined as the attribute of the electricity system whose installations are

adequate to supply demand. Adequacy concept is under capacity payments. On the other

hand, service security is defined as the response capability of the system, or a part of it, to

withstand contingencies and minimize consumption loss through the action of backups and

ancillary services. Therefore, ancillary services are related to system security.

The Chilean law states does not link payments for the security of the system to energy, nor

capacity payments. The Supreme Decree No. 130 (DS130) was enacted in 2011 and

provided the framework for the payment (the so-called compensation of incurred costs) of

ancillary services. Its first application was carried out on March, 2016.

According Law 20.936 (enacted in 2016), ancillary services are defined as: “Features that

allow the coordination of the operation of the system under the terms stipulated in article 72-

1 of DFL No. 4 (i.e. according the coordination principles of the operation). Ancillary services

are at least, the frequency control, the voltage control and service recovery plans, both under

normal conditions and under contingencies“

The law establishes that the ISO shall require the participants to comply all the technical

regulations, including the provision of ancillary services. Hence, the provision of ancillary

services is mandatory for the installations that are enabled to do so (therefore, an enabling

process is carried out). Enabling installations to provide ancillary services is in charge of the

ISO (sometimes with the use of third-party qualifying bodies). In fact, the determination,

administration and operation of ancillary services is determined by the ISO, as well as the

pricing and remuneration of them. Every generator must provide the necessary means (and

infrastructure) to exercise an adequate provision of services. In the case of lack of means

for correctly providing those ancillary services, the ISO has the power to apprise the

implementation of necessary resources or infrastructure.

The 4 main ancillary services contemplated by the ISO, are:

Frequency Control

Voltage Control

Service Recovery Plans (Installation and Operation)

Load Shedding Schemes

At the moment, ancillary services provision is not a market. In fact, power plants do not see

incentives to make a business case on the provision of ancillary services (and therefore

indicatives to flexibilize the assets remain quite limited). The supply of ancillary services

results from the centralized dispatching carried out by the ISO. However, the creation of a


formal ancillary services market is under development, and is expected to have all the

necessary regulation by 2020. The regulator is already working on this topic, considering

the importance due to the merging of both systems and the continuously increasing RES

penetration in the system.

4.3.1.1. Primary Frequency Control (PFC)

According to grid code and ISO reports, Primary Frequency Control can be defined as:

“Control action performed by the load/speed controllers of synchronous generators and by

the frequency/power controllers of wind farms, solar parks and active energy compensation

equipment, enabled to automatically modify their active power production, with the aim to

correct the imbalances between generation and load in the interconnected system, thus

correcting the frequency deviations of the system”.

In practice, depending on the grid, the Primary Frequency Control is carried out in a different

way.

In the case of SIC, PFC is mainly provided by hydro power plants (water reservoir). The so-

called pilot plant. This pilot plant, has a near zero droop, and is supported with other hydro

plants with low values of droop (~3%). This pilot plant is set by the ISO. Under certain

hydrology conditions of the system (droughts), OCGT plants (e.g. Candelaria or Taltal) can

also be used to provide primary reserve.

In the case of SING, the PFC is carried out by leaving a spinning reserve in every enabled

unit, working at a de-rated power (7% reserve) to provide the required primary reserve.

In a similar way to Europe, primary reserves are annually determined in a techno-

economical study called: “Frequency control and reserve determination study”. The following

amounts were estimated for 2017, broken down into Primary Reserves used for normal

demand deviations, and Primary Reserves used under contingencies (e.g. outage of a

power plant).

Table 15. Estimation of reserve for primary frequency control – Year 2017

All installations to be qualified to carry out the PFC, must comply with given requirements,

specified in the grid code (Chapter 5). The main requirements for speed controllers of each

synchronous machine are the following:

Adjustable droop under load conditions. Units driven by steam turbines may require

to stop the prime mover to change droop’s value. Droop settings are the following:

o Hydro: 0% – 8%

o Thermal: 4% – 8%

Max Deadband of ±25 [mHz] (0.1% of nominal frequency: 50 Hz).

Initial delay of load/speed system action under 2 seconds.

Max establishment time:

o Hydro: 120 seconds

o Thermal: 30 seconds

Oscillations must be damped under all operating regimes (Pmin, Pmax, other values).

System PFC (Demand

Variations) PFC

(Contingencies) Total PFC

SIC 57 MW 221 MW 278 MW

SING 42 MW 98 MW 140 MW


Solar and wind plants are obliged to perform PFC during over-frequency situations. Of

course, their participation in is always limited by the availability of the primary resource and

mainly in downwards direction.

4.3.1.2. Secondary Frequency Control (PFC)

According to grid code and ISO reports, Secondary Frequency Control can be defined as:

“Manual or automatic action destined to correct the permanent frequency deviation resulting

of the action of PFC performed by the load/speed controllers of the generators and/or by the

frequency/power controllers of the active energy compensation equipment arranged with

that purpose.

SFC action must be maintained during the necessary time to maintain the frequency within

an admissible range, referred to its nominal value. This action can be performed in the order

of several seconds to a few minutes, according to the response capability of the generation

unit determined in its qualification to provide this service, and without exceeding 15 minutes.

It is SFC’s task to re-establish system’s frequency to its nominal value, allowing PFC

participants to re-establish their active power value to reference values at the nominal

frequency”.

In Chile, SFC actions are mainly carried out manually (called manual re-dispatch) since

Automatic Generation Control (AGC) systems are currently being implemented. Depending

on the grid, Secondary Frequency Control is carried out in a different way.

In the SIC, SFC is provided together with the PFC by the pilot unit, plus the manual re-

dispatch of other generation units. Normally, pilots units are reservoir hydro units such as El

Toro, Pehuenche, Colbún and Rapel.

In the SING, the control is usually carried out by CCGT units. Most of the time the unit

performing SFC is the Tocopilla U16 unit.

Secondary reserves are determined together with the primary reserves. The following

amounts were estimated for 2017, specifying the values for two different time blocks

(different in SIC and SING).

Table 16. Estimation of reserve for secondary frequency control – Year 2017

System SFC (SFC Offpeak) SFC (SFC Peak)

SIC 124 MW 188 MW

SING 112 MW 132 MW

AGC is under implementation, the grid code outlines some technical requirements that the

power plants should meet (so they can be eligible for AGC participation). For instance,

individual units (or power plants as a whole) participating in SFC must have a minimum

ramp-rate higher than 4 MW/min.

4.3.1.3. Voltage Control

According to NTSyCS and ISO reports, Voltage Control can be defined as:

“Set of actions destined to maintain operating voltage within an allowed band”.


Voltage control is carried out by equipment that can inject/absorb reactive power

(generators, reactive compensators, reactors, condensers, converters from RES) and other

voltage control elements like on-load tap changer transformers. As in Europe, RES are

required to provide certain capability curves (PQ diagrams) and to perform voltage control if

required by the TSO.

When making the voltage control, two actions can be distinguished:

Automatic local action through an Automatic Voltage Regulator (AVR), included

local static compensators.

Automatic or manual centralized action to coordinate the control actions of local

regulators.

Remuneration of Voltage Control is regulated in the same way than primary and secondary

frequency control (same study), but taking into account the particularities of reactive power.

Besides power plants, other equipment is used to control (SVC, STATCOM, etc.).

4.3.1.4. Service Recovery Plans (SRP)

According to NTSyCS and ISO reports, Service Recovery Plans can be defined as:

“Set of actions oriented to re-establish the electric supply in a safe, reliable and organized

way, in the shortest time possible, after a total or partial blackout”.

Service Recovery Plans include at least the following services: Black Start, Fast Isolation,

and Synchronization Equipment for synchronization of electric islands. The SIC has an

additional service designed to avoid blackouts in extreme situations: Defense Plan against

Extreme Contingencies.

Remuneration of Service Recovery Plans is regulated through same study than the other

services. Additionally, in case of an event, the real operating cost of Service Recovery Plans

installations must be compensated such as the fuel consumption from an aeroderivative

Gas Turbine used during black-start (e.g. Tocopilla TG3).

4.3.1.5. Load Shedding Schemes

According to NTSyCS and ISO reports, Load Shedding Schemes can be defined as:

“Set of control schemes that release the trip order of a certain switch supplying a load, prior

operation of a local relay or the remote decision of tripping”.

This ancillary service is provided by clients, and its implementation is based on a techno

economical evaluation. Payments are per event and are in function of the ‘short-run failure

cost’.

Load shedding must be carried out only at abnormal conditions of the grid which can cause

stability risks. It also does not represent a control strategy of a certain variable, but a way to

avoid a major damage or problem in the grid.

4.3.1.6. Evolution mechanisms in the regulatory framework for ancillary services

Before Supreme Decree No.130 (DS N°130) enactment, ancillary services were considered

as part of the capacity payment, under the concept of security of service. Half of the security

of service payment was directly related with ramp rates of the power plants and the other


half was related with startup times. Power plants had incentives to improve their operational

parameters, as part of their capacity payments depended on them. The DS N° 130

regulation took out the security component of capacity payments (which started to be

remunerated according Supreme Decree No.62), and eliminated payments associated with

it. Hence, incentives to power plants to improve their operational parameters disappeared.

In order to promote flexibility in the system, it is important to find mechanisms to incorporate

these operational parameters in payments that generators receive.

4.4. Emission limits in Chile for thermal power plants

In Chile, the main legal framework applicable to power plant emissions is the DS N° 13/2011,

also known as the Norma de Emisiones para Centrales Termoeléctricas, the emission

standard for thermal power plants.

As of 2016, all the power plants in the country with a thermal input equal or greater than 50

MWth have to comply with emissions limit values for PM, SO2, NOx and Hg, with the

exception made for cogeneration installations.

The emission limits values are summarized in Table 17 and Table 18. Values are for normal

ambient conditions which are, according to the DS N° 13/2011, ambient temperature of 25°C

and ambient pressure of 1 atm.

Table 17: Emission limit values for power plants built or declared under construction before 2011

Fuel Particle matter

– PM

(mg/Nm3)

Sulfur Dioxide

- SO2

(mg/Nm3)

Nitrogen

Oxides - NOx

(mg/Nm3)

Mercury – Hg

(mg/Nm3)

Solid (6% O2) 50 400 500 0.1

Liquid (15% O2) 30 30 200 -

Gas (15% O2) - - 50 -

Table 18: Emission limit values for power plants built or declared under construction after 2011

Fuel Particle matter

– PM

(mg/Nm3)

Sulfur Dioxide

- SO2

(mg/Nm3)

Nitrogen

Oxides - NOx

(mg/Nm3)

Mercury – Hg

(mg/Nm3)

Solid (6% O2) 30 200 200 0.1

Liquid (15% O2) 30 10 120 -

Gas (15% O2) - - 50 -

The DS N° 13/2011 does not specify the particulate diameter for the PM limit. ELL

understands that the ELVs applies for the total particulate matter emitted into the air.


Emission limit values are applicable 95% of the time in operation11, whatever the load of the

power plant. The 5% of non-compliance are related to start-up and shut down periods (for

OC-, CCGTs and Rankine, emissions level are usually exceeded at start-up and shutdown),

as well as eventual trip of the unit, or malfunctioning of the FGT devices.

At date of publication of this report, there is no ELV at a national level and specific for

thermal power plants for Carbon Monoxide (CO).

Apart from the DS N° 13/2011, it is important to mention that all the power plants in Chile

with a power output equal or greater than 3 MW are subject to a local environmental permit

also known as Resolución de Calificación Ambiental – RCA.

There are examples of power plants, such as the site of Guacolda (Region III), where the

local permit is stricter in term of emissions than the DS N° 13/2011.

Evolution mechanisms related to emissions limits in Chile

In the Figure 51 below ELL represented a timeline of the main regulatory changes related

to power plant emissions in Chile, for the past three decades.

Figure 51: Main changes in the legal framework for power plant emissions in Chile, for the past threethree decades

Before the entry into force of the DS N°13/2011, most of the technologies for emission

abatement for Rankine cycles were de-dust devices, either electrostatic precipitator (ESP)

or fabric filters (FF). For gas turbines, de-NOx devices were in service, either water injection

or Dry Low NOx Burners (DLN) [28].

11 With the exception of NOx ELV for power plant built before 2011: 70% of the time in operation.


When the DS N°13/2011 came into force in 2011, most of the Rankine power plants either

closed (U10 & 11), or retrofitted their flue gas treatment system to comply with the new ELVs

within the deadlines set by the D.S.

At the date of publication of this report, the majority of the Rankine plants are now equipped

with de-dust devices (ESP / FF), de-SOx devices (either wet, semi-wet, seawater or dry).

Besides, the Rankine plants built after 2011 are equipped with SCR for NOx capture.

Most of the OCGTs and CCGTs are equipped with water injection system or DLN.

In 2017, the emission taxation, also known as Impuesto Verde – the green taxation, came

into force. All the power plants with a thermal input equal or greater than 50 MWth have to

pay a tax based on CO2, PM, SO2 and NOx emissions. The first payment of this tax is due

in April 2018 [29].


5. Gap analysis

In this section, ELL develops a gap analysis between the current situation in Chile and the

reference cases taken in Europe. Gaps in the definition of the operational parameters in the

NTSyCS and in the performance of the fleet of thermal assets were identified and are

presented below.

5.1. Gaps in Definitions for Operational Parameters

In this first part, ELL compares the definition of the operational parameters as they are

defined in the NTSyCS, to the definition of the operational proposed in the part 2.1.2 and in

the European, Italian and Belgian grid code.

The major gaps in the definitions are commented below.

Minimum power output (Pmin)

In Chile, the Pmin is defined as the minimum gross active power in which the unit can operate

permanently and deliver power to the grid without introducing disturbances to the system,

at RSC.

This Pmin is only based on the technical capacity of the plant and does not take into account

the ELVs. As of 2017, there is no environmental compliant Pmin (Pmin, env) defined in the

NTSyCS. However and as presented in the part 4.4, the DS N° 13/2011 which governs the

emission limits for thermal power plants clearly states that the ELVs are applicable 95% of

the time in operation12, whatever the load.

The power plants are asked to declare the technical Pmin (Pmin, tech) which, for the case of

OCGTs and CCGTs for example, is not necessarily equal to Pmin, env. This was clearly shown

by DNV GL in [30] for the power plant of Gas Atacama. For Gas Atacama13, at the date of

this report, the Pmin value reported in the database of the CDEC SING was the Pmin, env, and

not the Pmin, tech.

The incompatibility between the DS N° 13/2011 and the NTSyCS for power plants operating

at low load creates confusion on which Pmin shall be declared to the CDECs.

Start-up times

In Chile, the start-up time is defined as the time necessary to transit from standstill to

minimum power (Pmin). In practice, this corresponds to the time between the start request

from the TSO and the moment the power plant reaches Pmin as represented in Figure 52.

Two types of start-ups are defined: cold and hot. A cold start up is a start-up during which

the power plant shall carry out all the thermal processes in order to warm up the boiler and

reach Pmin. This is typically a start-up coming after an overhaul of the unit. Inversely, a hot

start up is defined as a start-up during which all the thermal processes are not necessary to

bring the unit to Pmin (coming typically after a trip).

12 With the exception of NOx ELV for power plant built before 2011: 70% of the time in operation. 13 And based on the information made available in [29].


Figure 52: Definitions of start-up processes for a Rankine cycle: According to ELL (green) and according to the NTSyCS (pink)

Gap 1:

The NTSyCS does not foresee a warm start-up, which would better represent a start-up

coming just after a weekend shutdown.

As presented in 2.1.2 and 3.3, a definition based on the previous downtime is preferred

convention for ELL since it enables to define more start-ups depending of the physical state

of the unit. Some manufacturers also define different types of start-up depending on the

temperature of the tubes of the boiler. Lastly, some power utilities use start-up curves as a

function of the shutdown time, such as the one in Figure 53.

Figure 53: Example of a start-up curve for a CCGT


Gap 2:

The preparation time can change a lot depending on the operational state of the power plant

at the start request. As a reminder, Figure 16 is re-presented below:

Figure 54: Typical preparation times for a CCGT. Preparation times vary from a few dozen of minutes for a hot start-up with the vacuum kept in the condenser to more than 10 hours for a cold start-up,

after an overhaul of the boiler (i.e. boiler dry)

In particular, if the boiler of the unit is dry, which is typically the case after an overhaul of the

boiler, the preparation time can exceed 12 hours. Inversely, if the boiler is already filled, and

if the vacuum was kept in the condenser, the preparation time can last, for the same plant,

a few dozen of minutes only (between 10 and 30 min).

The operational state of the power plant at (t = 0) is not mentioned in the NTSyCS. Therefore,

it is up to the power plants to include or not the filling process of the boiler, and/or the creation

of the vacuum in the condenser, which strongly impact in the end the total start-up time. This

is probably the reason of the high spread in the cold start-up times that one can observe in

Chile, in particular for the Rankine cycles (see Figure 58).

Ramp rate, minimum uptime and downtime

These three operational parameters have not been formally defined in a technical annex of

the NTSyCS. However they are declared by each of the units to the CDECs [31].

5.2. Gaps in the grid organization, energy and ancillary markets

This section provides a comparison between Belgium, Italy and Chile, with the main

highlights.

Grid infrastructure

This section compares the three countries for the power grid infrastructures. The latter can

be considered as specificities that cannot be changed at short term, since they are linked to

investments.


Table 19. Grid infrastructure comparison

Belgium Italy Chile TSO Single TSO: ELIA Single TSO: TERNA Two main grids: SIC &

SING (connection in progress). Two TSOs.

Grid configuration

Meshed grid Antenna grid with 6 zones (reflecting transmission

bottlenecks)

Large extension, barely meshed and some

bottlenecks.

International connections

Large cross-border capacities with shared

ancillary services

Limited cross-border capacity without sharing of

ancillary services (excepted PFC)

Almost no cross-border capacity. “Stand alone”

grids.

Market coupling Fully coupled with MRC Yes, partly coupled with MRC

Not applicable

Electricity price Most of the time the same as NL, FR and DE unless the international lines are

saturated.

Different prices with border countries and even

between national “zones”, due to the saturation of the

capacity.

Different between border countries and 2 grids.

Merit order – most expensive

generator (Low/High

residual demand)

Nuclear + hydro / CCGT (old)

CCGT and Cogen / CCGT (old)

SIC: Coal + Hydro / Hydro + CCGTs (+OCGTs) SING: Coal + CCGT /

CCGT + Engines

Installed power 19 GW 102 GW SING: 5.5 GW SIC: 17.2 GW Total: 22.7 GW

Peak load ~13 GW ~54 GW SING: 2.4 GW SIC: 7.5 GW Total: 9.9 GW

Wind and solar capacity (%

installed capacity)

10% w/o decentralized solar PV

25% w/ decentralized solar PV

13% SING: 10%; SIC: 13%

Mainly due to the shape of the country and the presence of islands, the Italian grid shows

more bottlenecks than in Belgium and less international connections. This is reflected in the

price differences not only between Italy and the surrounding countries but also between the

different zones in Italy.

The situation in Chile is even more complicated than Italy due to the very extended shape

of the country. It explains the existence of 2 separate grids which are currently being

connected. In addition, grids are almost stand-alone as the cross-border are almost

inexistent. This is a major difference with Italy and Belgium which are part of the large

European synchronous area and explains the larger reserve needed for the ancillary

services.

The penetration of non dispatchable RES (wind and solar) is similar in the 3 compared

countries when considering large scale plants (10-13%). However, it is significantly higher

in Belgium when considering the rooftop PV (25%).

Belgium is a small country with strong international exchanges and pumped hydro capacity.

Hence this gives more flexibility for the grid management and should be taken into

consideration in the comparisons with Italy and Chile.


Energy market organization

This section compares the organization of the energy market in the different countries.

These market rules could possibly change on a short period of time but strongly depend on

the political / conceptual choices of the countries.

The organization of the energy market is also strongly influenced by the “power balance”

between the TSO and producers, congestion in some areas and the strength of the

interconnections.

Table 20. Energy market comparison

Belgium Italy Chile TSO – producers “power balance”

More balanced power between TSO and ARPs

Strong TSO position wrt producers

Very strong TSO position wrt producers (central

dispatching) Dispatching Market until few minutes

before delivery. High responsibility for “ARPs”.

Market up to 1-2h before delivery. TSO takes the

lead afterwards.

Centralized dispatching

Imbalance responsibility

ARPs are in charge of the balancing of their “pool” of

plants

Each asset has to follow its scheduled load curve

Each asset has to follow its scheduled load curve

Energy payments Bid mechanism and “pay-as-cleared” price (Day Ahead and Intraday).

Close to marginal cost but no obligation.

Bid mechanism and “pay-as-cleared” price (Day Ahead and Intraday).

Close to marginal cost but no obligation.

Audited cost mechanism and “pay-as-cleared” price.

Merit order based on marginal costs (to be

justified). Capacity payment Not for “standard” energy

supply. See next section for

ancillaries.

Not for “standard” energy supply.

See next section for ancillaries.

New rules in discussion.

Yes, for all plants based on system adequacy

(independently of ancillary services)

Imbalance penalties

TSO provides incentives if the imbalance

compensates international imbalances (ACE).

Consequence: ARPs try to anticipate trend.

Imbalances are always penalized. Amount

depends on international imbalances. Consequence:

all plants try to follow the load curve.

Non existent

Preventive system security action of TSO

“Strategic Reserve”. Not activated so far.

“Essential plants”. Regular activation where the

interconnections are weak.

Inherent to centralized dispatching

Following the different liberalisation directives, Europe made the choice of a deregulated

energy market with minimum intervention from the TSO for the dispatching (except Poland).

This strongly differs from Chile and its centralized dispatching.

Even though Belgium and Italy have to comply with the same European Directives, major

differences exist in the organization of the electricity market:

Generally speaking, the obligations are given for a pool of plants (ARPs) in Belgium

and individual plants in Italy

Exchanges on the Intraday market (between ARPs) are allowed up to the last

moment in Belgium whereas the TSO takes the lead in the last 1-2 hours in Italy.

Incentives are given in Belgium to support the grid for the cross-border balancing.

This tends to optimize the production costs but makes the evolution of the

imbalance more volatile on a day. TSOs tend to increase the volume of inter-TSO

exchanges to decrease the costs and volatility. In Italy, the plants follow their load

curves as much as possible due to the large penalties on imbalance.


In Chile, the dispatching is managed by a central authority which imposes the load set point

to the individual power plants. Cross-border exchanges are almost inexistent for Chile.

The remuneration of the energy supply is managed by the market in Europe and a

centralized authority in Chile but both organizations result in a payment close to the marginal

costs, with the major difference that the plant costs are audited in Chile. The energy price is

supposed to include the costs related to the investment in Europe but this under pressure

due to the overcapacity.

Capacity payments are not easy to implement in Europe as they could bias the market.

There are currently no capacity payments in Italy but a new system is being implemented

(see section 2.3.7). In Belgium, a kind of capacity payment is foreseen for the Strategic

Reserve. Such mechanisms have to be approved by the European Commission.

In Chile, the capacity payments are a cornerstone of the system as they cover the

investment costs of the plant operators. They are provided based on the “system adequacy”,

which currently does not give many incentives for performance improvements.

Ancillary services

This section compares the organization of the ancillary services in the different countries.

They are particularly important to provide flexibility to the system.

Table 21. Ancillary services comparison

Belgium Italy Chile PFC (R1) Applicable to selected

plants. International bids

accepted.

Applicable to all plants. International bids not

accepted.

Applicable to selected plants. SIC: One near zero

droop unit (pilot unit) + other low droop plants (~3%). SING: Selected

units operate at a derated power (7%).

PFC volume definition

3000 MW for European synchronous area. Shared between countries based on energy generation (ENTSO-e).

Defined annually by CEDEC

PFC reserve14 73 MW (0.6% peak) 520 MW (1.0% peak) SING: 140 MW (5.8% peak)

SIC: 278 MW (3.7% peak) On-line PFC

testing As from 2017 Already applied No

SFC (R2) Applicable to selected ARP (pool of plants).

Applicable to selected individual plants.

Applicable to selected units. SIC: Together with R1 by pilot unit + manual

redispatch. SING: Manually carried out.

SFC reserve 140 MW (1.1% peak) 800 MW (1.5% peak) SING: 132 MW (5.5% peak)

SIC: 188 MW (2.5% peak) TFC (R3) 15’ start-up time.

Based on “true” costs. For thermal plant:

contractual start-up time (max 120’).

Based on “willingness to be called” bid.

Part of central dispatching management.

TFC reserve 1000 MW (7.7% peak) 3500 MW (6.5% peak) TFC used by CDEC but not declared in the norm

Reactive power Paid Mandatory and not paid Paid

14 % defined as a percentage of peak load


Other services Strategic Reserve, black start

Black start, Essential Plants

Service Recovery Plan (including black start),

Load Shedding Schemes

Selection for the service

Based on a bid process Optional participation

Based on a bid process Obligation to bid the

available reserve

Based on central dispatch scheme

Need for verification by third party entity

Capacity payment

On all ancillary services (including R1, R2 and R3) and for strategic reserve.

Only for essential plants (compensated for “extra

costs” to be justified)

No capacity payments, but a compensation for the extra costs to provide

ancillary services (based on a study of costs).

Supervision & Penalties

ELIA verifies the non-compliance of power plants in terms of availability and

activation of ancillary services. Specific penalties

defined by ELIA apply to each ancillary service

TERNA verifies the performance of power

plants with respect to their frequency-control model. Penalties apply for any

deviation from the model.

ISO verifies the performance of power

plants according to grid code

No specific penalties defined for ancillary

services

Notified Body certification

No. But qualification to ELIA is required.

Yes for R1 and R2 No

Ancillary responsibility

ARP are responsible for delivering the service.

Obligations can be transferred to counterparts.

Plants are responsible for delivering the service. Obligations may not be

transferred.

Plants are responsible for delivering the service. Obligations may not be

transferred.

Participation of the DSM

Yes for all services. No No

Participation of the RES

No No Yes

International contracts

Yes, for R1. Discussions on-going for R2.

Discussions on-going for R1 and R2.

No

Ex-ante / ex-post mechanisms

Both applied by TSO Both applied by TSO Yes. Part of centralized dispatching

Even though Belgium and Italy have to comply with the same European Directives, major

differences exist in the organization of the ancillary services:

No capacity payment for the availability of ancillary services in Italy, whereas it is

applicable to all services in Belgium. A new system is being implemented in Italy

though.

Participation of all plants for the PFC in Italy

Obligations attributed to the ARP in Belgium (pool of plants) and individual plant

requirements in Italy

Start-up time is less important for the thermal plants participating to TFC in Italy

(thanks to the pump-storage hydro capacity)

Stricter verification of the plant performances in Italy (notified bodies)

Participation of DSM to the ancillary services in Belgium, not yet in Italy

In the context of the centralized dispatching in Chile, the contractualization of the ancillary

services between the TSO and plant operators is not as necessary as in Europe where a

similar situation used to exist before the liberalisation.

In addition, the total reserve for PFC and SFC is much higher in relative terms than in Europe

due to the smaller size of the grids (higher relative importance of the large units) and the

“stand-alone” situation (vs large synchronous area).

Other points of interest in Chile are listed hereunder:


No bid market for ancillary services and no specific capacity payment: the selection

is made by the central authority based on a techno-economical choice

VFR approach is different in SIC and SING: like Belgium for SIC (selected units)

and like Italy for SING (de-rating on all thermal units)

No on-line testing of the PFC

Requirements are imposed at individual plants level (as for Italy)

Tertiary reserve is part of the central dispatching management (not a specific

“requirement”)

No participation of DSM but participation of the RES.

5.3. Gaps in the operational parameters of thermal power plants

In this section, ELL compares the start-up time, the ramp rate, the relative turndown, the

minimum uptime and downtime of the thermal assets in Chile to the P10, P50 and P90 of

the fleet of thermal assets taken in Europe and presented in the part 3.4.

As a reminder, P10, P50 and P90 are defined in the figure below:

Figure 55: Definition of P10, P50 and P90

Most of the numbers related to Chile come from the database of the CDECs, and information

provided by GIZ.

It is important to mention that the operational parameters which are compared in the

benchmark are according to the definition in 2.1.2 for the fleet in Europe, and

according to the NTSyCS for the fleet in Chile which are not always identical.

ELL estimates that the gaps due to differences in the definitions are negligible, with

the exception of the start-up times.

In the gap analysis, only the cold start-up times are compared for Rankine cycles and

CCGTs. In reality, this parameter does not reflect their real ability to participate in the

ancillaries services (mainly TFC). Hot or warm start-up time would have been more relevant

for flexibility, but the cold start-up times were the only start-up times published in the

databases of the SIC and the SING.


Rankine cycles

All the Rankine cycles are subcritical units in Chile. For comparison, ELL used the

performance benchmark values of the European fleet of Rankine cycles without the USC

units.

5.3.1.1. Relative turndown

Figure 56: Rankine cycles – Benchmark on turndown

For the case of the Rankine cycles in Chile, and excluding the plants of Laguna Verde U1

and U215, relative turndowns range between 60.5% (P90) and 36.7% (P10), with a median

value (P50) of 46.7%.

With more than half of the fleet with relative turndown lower than 50%, Rankine cycle units

in Chile are found to be average. Top performers in Chile (Laguna 1 & 2 excluded) are the

units of Guacolda with a turndown of 60%. These units are subject to cycling operation due

to the relatively high penetration of renewables in the region. It is interesting to mention that

according to the experts of STEAG who conducted an audit of the Pmin on Guacolda 1 to 4,

the technical minimum were found “unusually high” [32].

The fleet of Rankine units taken in Europe is not much flexible neither. A high spread in

turndown values is observed between the base load units (P10) and the cycling units (P90).

For example, the turndown of base load power plants is between 42 and 46% only, but a

value of 65% or more is reached for cycling units.

Relative turndown between 50 to 60% are common values in literature for existing pulverized

coal boilers, depending on the type and generation, and the type of fuel [5], [33], [34]. As

mentioned before in this report, it is generally admitted that Pmin can be reduced up to reach

70 to 80% of relative turndown by switching off some burners and coal mills. Depending on

the cases, this can require some changes on mill and burner design, or operating ranges.

15 Laguna Verde U1 and U2 are (extremely) old PC boilers retrofitted to diesel / fuel oil combustion and dedicated to cold reserve.


New and flexible boiler design can reach turndown higher than 80%, in particular if the power

plant can run in single-mill operation [5].

5.3.1.2. Ramp rate

Figure 57 : Rankine cycles – Benchmark on ramp rate

With a P50 of 1.84% Pmax/min, the median ramp rate in Chile is in the range of the value

found in the technical literature [33]. A relatively high spread is observed between best (and

cycling) units and worst performers (4 MW/min or 2.63% Pmax/min for Guacolda 4 to compare

to 0.75 MW/min or 0.47% Pmax/min for CTTAR).

In Chile, top performers for relative ramp rate are the smallest units (Tocopilla U12 and U13).

In absolute values, load ramps for these units are equivalent to the plant of Guacolda 3, 4

and 5 (2.6 % Pmax/min or 5 MW/min), but the smaller Pmax of U12 and 13 make their relative

ramp rate higher.

According to technical literature, such as [5] load ramps for conventional subcritical PC

boilers typically range between 2 and 5% Pmax/min. However in practice, ramp rates in the

ranges of 1.8 – 2% Pmax/min are more common for boilers with a capacity of 180 to 300 MW,

which are typically the PC boilers installed in Chile [33].

For the fleet of Rankine cycles in Europe, ramp rates are lower than ones mentioned in the

literature. It is interesting to mention that in the same way as turndown, the ramp rate of the

cycling units (typically 2.9% Pmax/min or 10MW/min) is much higher than for base load units

(0.64 % Pmax/min or 3MW/min).


5.3.1.3. Cold start-up time

Figure 58: Rankine cycles – Benchmark on warm - cold start-up time

The cold start-up time varies from a factor of one to four across the fleet of Rankine cycles

units in Chile. As ELL previously mentioned, this could be due to the lack of precision in the

definition of the start-up process, regarding the state of the power plant at the start up

request.

According to technical literature [35], [34], [32], it takes roughly between 8 and 12 hours to

start-up a Rankine unit in cold conditions (from the notification to start to the Pmin, with the

assumption that there are little preparation works to perform on the boiler and on the

condenser). Most of units in Chile have considerable higher start-up times.

European fleet values are clearly lower, however the definition of start-up time is not the

same and this affects the direct comparability of the units.


Minimum uptime

The minimum uptime of Rankine cycles ranges between 6:30 for the most recent unit

(Cochrane 1 and 2, commissioned in 2015) and up to 5 days for older installations (namely

CTM1 and 2, and Santa Maria) which are found much longer than the fleet in Europe. As a

comparison, minimum uptime in Europe typically ranges between 5 and 12 hours, but almost

never exceeds one day.

As mentioned in 5.1.3, there is no formal definition of the minimum uptime in the NTSyCS.

Besides, there is no technical limitation which justify a minimum time in operation. Minimum

uptime results from other reasons, contractual or strategical for example [31].


Minimum downtime

The minimum downtime of Rankine cycles in Chile ranges between one and two days. This

is found much longer than for the fleet in Europe, where minimum downtimes are in the

range of 2 to 6 hours.

Just like minimum uptime, there is no formal definition of the minimum downtime in the

NTSyCS. As mentioned in 3.3.1, there are technical limitations which can limit the minimum

downtime for Rankine cycle, but rarely for more than a few hours.

CCGTs

Only the performance in 1+1configuration (i.e. 1 GT + 1 ST, also noted 1 GT + 0.5 TV in

CDEC SING – for Kelar and Gas Atacama) are considered in the benchmark. However,

these might not be fully be representative of the real performance of the units.



Figure 59: CCGTs – Benchmark on turndown

In Chile the top performer of the fleet is the unit U16, where an upgrade of the turbine has

recently been installed to enhance the load flexibility (so-known low park load mode, specific

to the GT26 gas turbine). With more than half of the fleet with relative turndown lower than

40%, and with the exception of the U16, the fleet of CCGTs in Chile is not found load flexible.

For CCGTs, turndown typically ranges around 60%. According to ELL, relative turndown

values lower than 40% are typically low for CCGTs, even for old units and even more for a

country where there is no restriction on CO emissions (see part 5.4).

It is important to mention that in the Figure 59, nearly all the CCGTs in Europe made efforts

the last years to reduce Pmin / increase Pmax and enhance the load flexibility.

Note that the Pmin tests performed during the audit of Gas Atacama showed that the relative

turndown of the site could be increased from about 20% to 45.3% while still complying with

emission limits (represented as CC*16 in Figure 59).

16 CC* turndown is calculated with the environmental compliant Pmin_env observed by DNV GL with natural gas


5.3.4.2. Ramp rate

Figure 60: CCGTs - Benchmark on ramp rate

Load ramps in Chile are found conservative in comparison to technical literature and the

ramps of the CCGTs in Europe, where efforts were made to increase the ramps (see Figure

45 for example).

For CCGTs, technical literature says that ramp rates are typically in the range of 15 to 25

MW/min [35]. This range of load ramps is rather consistent with the values observed for the

CCGTs in Europe. In Chile, P10 for ramp rates only reaches 3.8 MW/min and the median

value, 10 MW/min.


5.3.4.3. Cold start-up time

Figure 61: CCGTs - Benchmark on cold start-up time

CCGTs in Chile and in Europe have comparable cold start up times. As mentioned before,

not all units have optimized their start up time, probably due to the lack of incentives. Not all

the CCGTs in Europe do not always have incentives to reduce the cold start-up times, which

explains according to ELL the big gap between P10 and P90.

This would mean there is important room for improvement regarding the start-up times of

the worst performers in both, Chilean and European fleet.

For CCGTs, cold start-up time typically takes 4 hours or less [30]. The start-up time is a

flexibility lever that can be improved rather easily with low-to-moderate CAPEX initiatives.

For example, a CCGT in Italy has successfully managed to reduce the cold start-up time

from 3:20 to about 2:10 with a deep revision of the start-up procedures, challenge of the

ramp rates defined by the OEM and increasing the automation of the start-up, among others.


Minimum uptime

Figure 62: CCGTs - Benchmark on minimum uptime

The minimum uptime for the combined cycles range between a few dozens of minutes for

Kelar (recently commissioned), and a day or more for CTM3, San Isidro 1 and Nueva Renca.

The values of the minimum uptime before (CC1 and CC2) and after the audit of Gas

Atacama (CC*) are mentioned in Figure 62.

This is found by ELL rather high. As a comparison, minimum uptime typically ranges

between 0 (P10) and 10 hours (P90) for the fleet of CCGTs in Europe. This is confirmed by

[30] where minimum uptimes between 1 and 2 hours are said to be common practice.

As mentioned in 3.3.2 and 5.1.3, and just like Rankine cycles, there is no formal definition

of the minimum uptime in the NTSyCS, and there is no real technical limitation which justifies

a minimum uptime. This parameter is more commonly established based on contractual

reasons (maintenance agreement for ex.) or based on the operation strategy, among others.

The minimum uptime for Nueva Renca Nehuenco 1 and 2 and San Isidro 1 were

provided by GIZ. They are not published on the website of the CDEC-SIC, so ELL could

not cross check these values.


Minimum downtime

Figure 63: CCGTs – Benchmark on minimum downtime

The minimum downtime for CCGTs is between 2:15 for Kelar and up to 8 hours for

Nehuenco 1 and 2 and Nueva Renca. The values of the minimum downtime before (CC1

and CC2) and after the audit of Gas Atacama (CC*) are both mentioned in the figure above.

Present minimum downtimes for the CCGTs in Chile are found in the range of the values

observed in Europe which are typically between 0 and 8 hours. [30] mentions minimum

downtime between 1 and 2 hours.

Just like for the Rankine cycles, there is no formal definition of the minimum downtime in the

NTSyCS. As mentioned in 3.3.2, there are technical limitations which can limit the minimum

downtime for CCGTs, but not more than a few hours.

The minimum downtime for Nueva Renca, Nehuenco 1 and 2 were provided by GIZ.

They are not published on the website of the CDEC-SIC, so ELL could not cross check

these values.


OCGTs


Figure 64: OCGTs - Benchmark on relative turndown

It is difficult to make a fair comparison for the Pmin of an OCGT since is strongly impacted by

the technology of the turbine and by the possible successive upgrades installed in the

turbine (compressor, combustion hardware, among others).

Since the main limitations for the turndown of an OCGT are the emissions of CO and NOx,

environmental limits strongly affect the turndown. In Chile the Pmin declared shall be the

technical Pmin, but it was observed that some units were declaring the environmental Pmin to

remain compliant with the emission limit values at any load, resulting in lower turndown.

In some cases, declaring the real technical Pmin would increase the turndown of Chilean

units.

To explain this situation, in Figure 64 ELL compared the environmental Pmin for a standard

GE 9E unit (environmental Pmin declared by Gas Atacama in OC is used as benchmark).

The Pmin declared for the same type of unit ranges between 60% to less than 40%.


5.3.7.2. Ramp rate

Figure 65: OCGTs - Benchmark on ramp rates

In Chile, with the exception of the sites of Yungay and Cardones, ramp rates are equal to or

below 10 MW/min. A third of the fleet including some aero derivative GTs, has ramp rates

equal to or below 5 MW/min.

In our experience, these values are found to be quite conservative. This impression was

confirmed after reviewing some datasheets communicated by the OEMs:

■ For aero derivative GTs, ramp rates are typically around 30 MW/min for GE LM2500

[36], and around 50 MW/min for GE LM6000 PC [37].

■ For heavy duty GTs, the ramp rate of a 9E.04 is normally around 16 MW/min [38].

Besides, ELL also knows a SIEMENS V94.2 used in OC in Europe with a ramp rate in

the range of 11 MW/min.


5.3.7.3. Start-up time

Figure 66: OCGTs - Benchmark on start-up time

In Chile, three quarters of the fleet of OCGTs declare start-up time equal to or below 15

minutes. The last quarter of the fleet have start-up times above 30 minutes, and even above

1 hour for the worst performers.

Significant differences in start-up times are also observed for a same technology. For

example, for the GE 9E, the start-up times declared to the CDEC range between 12 minutes

to 1 hour.

In our experience, the start-up time for the last quarter of the fleet is high, all the OCGTs

shall be capable to start-up within 30 minutes or less, with (eventual) limited efforts.

Differences in start-up times for a same technology can be explained by different strategy

of operation (shorter start-up times usually require more maintenance).

For comparison:

■ In Belgium, both heavy duty and aero derivatives GTs participate in R3 reserve, which

consist in being capable to start up at any time and in a maximum of 15 minutes

(represented with a grey line on Figure 66)

■ According to the datasheets for GE 9E.03 / .04 [38], start-up time for conventional use

is in the range of 30 minutes, and 10 minutes only for peaking use (represented in

purple on Figure 66)


5.3.7.4. Minimum uptime

Figure 67: OCGTs – Benchmark on minimum uptime

In Chile, minimum uptimes for OCGTs are between 0 hours (i.e. no minimum uptime) and

four to five hours for some units. Significant differences in minimum uptime are observed for

a same technology: Candelaria 1 and 2, and Los Guindos are three GE 9E, but the minimum

up time varies from 0 hours (i.e. no minimum uptime) to 4 hours.

5.3.7.5. Minimum downtime

Figure 68: OCGTs – Benchmark on minimum downtime


In Chile, the minimum downtime for OCGTs is between 0 hours (i.e. no minimum downtime)

and 1:15. For the fleet of GE 9E configured in OCGT, the minimum downtime varies between

20 minutes and one hour.

5.4. Gaps in emission regulations

In the part 3.3, ELL showed that emission limits are not a technical limitation to enhance the

operational flexibility of Rankine cycles. Inversely, CO and NOx emission limits play a key

role on the definition on the Pmax and Pmin of OCGTs and CCGTs. This is why in this section,

a focus is made on the OCGTs and CCGTs, and the NOx and CO ELVs only.

First, a benchmark is made between the ELVs of the DS N°13/2011 together with the P10,

P50 and P90 of the ELVs from the environmental permits of a representative fleet of gas

fired OC- and CCGTs in Europe, as well as the ELVs set in the IE-D.

Then, a comparison of the application of these different ELVs is made.

The benchmark of the ELVs for OC- and CCGTs is only possible for installation firing

gas, because diesel is not fired in the fleet in Europe used for the comparison.

Limit values

In the Table 22, the ELVs of the DS N°13/2011 for gas fired OC- and CCGTs (built before

and after 2011) are compared to the IE-D for existing and new built OC- and CCGTs, as well

as to the P10, P50 and P90 of the ELVs in the environmental permits in Europe presented

in Table 9.

All the values are corrected in normalized ambient conditions and O2 content. The ELVs

mentioned for the environmental permits in Europe are the maximum average concentration

allowed on a daily basis.

Table 22: Benchmark of ELVs of NOx and CO, for OCGTs and CCGTs in normalized ambient conditions and O2 content (15%)

mg/Nm³ OCGT

P10 P50 P90 IED DS13

NOx 33 50 75 50 50

CO 29 92.5 100 100 -

Two comments can be made with this table:

■ The ELV for NOx of the DS N°13/2011 is equivalent to the value of the IE-D, and to the

P50 of the daylily ELVs imposed in the afore-mentioned environmental permits. This

remark applies both for OC- and CCGTs.

■ There is no limit on CO emission in Chile.

mg/Nm³ CCGT

P10 P50 P90 IED DS13

NOx 41 50 93 50 50

CO 53 100 100 100 -


Application

In Chile, the NOx-ELV is applicable whatever the load. However, as presented in 4.4, new

power plants can exceed the NOx-ELV during a maximum of 5% of the time of operation

and existing power plant (built before 2011), 30% of the of the time of operation. The DS

N°13/2011 associates these non-compliance threshold to the start-up and shutdown times,

and eventual trips of the unit.

Besides, existing (i.e. built before 2011) OC- and CCGTs which operate less than 10% of

the year, or with a thermal input between 50 MW th and 150MWth are exempt from the NOx

ELV.

In Europe, the ELVs of the IE-D are only applicable in normal conditions of operation, which

do not include the start-up and shutdown nor the operation below 70% of the load. That

said and as mentioned in 3.3.4, nearly all the local environmental permits put restriction on

the emissions during the start-up and shutdown, or at part load which can be less strict than

the ELVs at base or near base load (for ex. NOx and CO ELVs = Base Load ELVs x 2).


6. Proposed Roadmap for the future

The previous sections presented the differences between Chile and two European countries

(Belgium and Italy) on the following:

- Organization of the power system, with a focus on the ancillary services

- Technical performances of the power plants with a focus on flexibility

Based on the gap analysis, this section highlights several proposals identified by ELL in

order to improve the flexibility of the power system in Chile. These recommendations are

based on a high-level evaluation and do not aim at integrating all plant and grid code

specificities. Each measure should be analysed in details with the stakeholders to verify its

applicability to the Chilean context. The ambition of this section is to feed the discussion on

the future of the power system based on the return of experience (pros and cons) in

European countries.

Lastly, some recommendations in this section may already be evaluated or are a part of the

action plan of the different stakeholders in Chile (TSO, government). ELL approach was to

mention all the measures which were judged relevant as a result of the gap analysis

performed in this study.

ELL understands that changing the remuneration for the ancillary services is a considerable

change in the financing scheme of the power plants. In addition, the current power system

in Chile is organized around a centralized dispatching which is very different from Europe.

Hence, the roadmap makes a difference between the following cases:

- Measures which could be taken with the current organization of the ancillary services

(no market)

- Measures applicable if an ancillary service market is put in place

- Measures applicable if an energy market (decentralized dispatching) is put in place

6.1. Measures which could be taken with the current organization

of the ancillary services (no market)

I/ Improve verification of plant performances

In the current system, power plants have to be very transparent towards the TSO regarding

their technical performances (unlike in Europe). ELL considers that the verification of the

performances announced by the plants could be improved with the following measures:

- Improve the definition of the technical parameters requested to the plants17

The definition of the plant technical parameters should be clearer for some of them,

as there is currently a room for interpretation. In ELL’s opinion, the technical

definitions to be reviewed are, among others, the following:

17 These measures may not be required if enough incentives are given to the plants for improving their performances (see item VI/ hereunder).


o The minimum power output Pmin. As of today, the Pmin declared by the power

plants to the CDECs is not always the Pmin as defined in the NTSyCS (i.e.

Pmin_tech). If they were asked to operate at Pmin_tech rather than Pmin_env,

OCGTs and CCGTs would not always comply with the emission limits of the

DS13.

o The start-up times. The trigger for the beginning of a start-up is not clear in

the definition of the NTSyCS. According to ELL, the “request to start” from

the TSO is the recommended trigger for the beginning of the start-up time.

The state of the power plant at the start request is not clear neither and could

strongly impact the preparation time (e.g. vacuum kept or not). Besides,

there are only two definitions of start-up (hot/cold). With:

More types of start-ups in the definitions or by using a start-up

curve for each units,

A clarification of the trigger,

The CDECs would have a better view on the necessary time for each plant

to start up after a short downtime, such as a weekend for example.

o The ramp rates. A clear definition of the ramp rate is not available in the

NTSyCS. A distinction can be made for standard ramp rates and maximum

ramp rates:

The standard ramp rate covers the whole operational range of the

unit, from Pmin to Pmax. It should be an average value and take into

account possible limitations close to some load set points, such as

Pmin or, Pmax. This ramp rate typically reflects the response of a unit

to load changes requested by the TSO.

The maximum ramp rates for specific operational ranges. This

ramp rate better represents the capability of a unit to provide PFC

and SFC.

o The minimum downtime and uptime. A clear definition of the minimum

downtime and uptime are not available in the NTSyCS.

- Implement on-line remote testing for PFC

The on-line testing of PFC-VFR (simulation of a frequency deviation) is already

applicable in Italy and is being implemented in Belgium. Since the spinning reserve

was identified as a possible weak point in the power system for large integration of

RES [13], it seems particularly relevant to verify regularly the real plant capabilities.

- Implement performance tests by an independent party

In the current system, regular performance tests are requested to the plants to

demonstrate Pmax. These tests could be extended to other technical performances

which are critical for the support to the grid: Pmin, start-up times, ramp rates, minimum

up and downtimes. The verification could be carried out with audits or with specific

performance tests executed by independent parties. In a central dispatch system,

plants may be tempted to declare a Pmin higher than reality as they could benefit from

additional revenues (higher energy generation).


The costs of such tests / audits should not be underestimated. Hence, ELL

recommends to focus on the criteria which are the most relevant for the stability of

the power system in Chilean’s context.

The requirements could be imposed at a “high level” to verify that the contractual

clauses are verified (e.g.: provide the SFC reserve within 30”) on a pass/fail basis

without entering into the technical details (e.g.: ramp rate exact values). This

recommendation is linked to the definition of clear products (see II/). Clear guidelines

should also be defined for the tests.

- Use a model for the verification of the plants response

In Italy, the plants shall provide a model of the expected response for PFC. Deviations

with respect to the model have to be justified and can ultimately be penalized. This

measure provides more predictability of the plant behaviour to the TSO but imposes

significant constraints to the plant owners. The need of such measure in Chile should

be evaluated with care.

II/ Package the requirements for the ancillary services in products

ELL recommends the definition of clear “products” for the supply of ancillary services. This

would clarify the requirements imposed to the plants providing those services and simplify

the comparison between the different suppliers. Specific products could also be defined to

enlarge the participation to different kind of plants and increase the competition if a market

is put in place (see V/).

- Package the ancillary services in clear products with standard contracts

Standard products for PFC, SFC and TFC (e.g.: supply the reserve in xx sec,

asymmetric participation) enable a transparent comparison between the different

actors in order to select the cheapest or most efficient ones (merit order on capacity

fee for selection, merit order on energy for activation). In Belgium, the “General

Frameworks” are published on the website of the TSO (ELIA).

Since the liberalisation of the market, the type of products for the PFC was diversified

in Belgium to include the participation of different type of power plants, including

nuclear plants (with different remuneration). This was a way to increase the

competition and decrease the costs.

The products should be defined in line with the needs of the power system (e.g.:

required gradients, start-up times).

In Chile, specific “products” could be set for coal plants (vs CCGT plants), in line with

their technical limitations. The remuneration would be less than for more flexible

products.

- Diversify the participants to the ancillary services

RES and DSM should be included in the standard products as much as possible. In

some cases, DSM can be cheaper than the activation of the cold reserve.

- Allow asymmetric participation for SFC

III/ Improve speed and accuracy of the grid and ancillary services management

- Prediction model for RES supply


The accuracy of the predictions of RES production is of utmost importance to

anticipate the variation of the residual demand and mitigate the effects on the thermal

plants. The continuous development / support of accurate models is key.

- Definition of the zone prices

As the configuration of the grid in Chile is similar to Italy, the best practice could be

exchanged with TERNA on the algorithm for the definition of the zone price. The Price

Coupling of Regions algorithm is also another reference. The right price signals are

needed to reflect grid congestion and provide suitable incentives for the ancillary

services.

- “ACE”- type system for the interconnection between the SIC/SING

After interconnection, the situation in Chile between the 2 grids will be very similar to

the different “Control Areas” in Europe. The best practices could be exchanged for

the definition and treatment of the “ACE” signal.

- Manage the hydro resource to keep enough flexibility

The management of the water resource is a constant balance between a cheap price

on the energy market and saving resources for the grid security. With the increased

penetration of RES, the participation of the hydro plants to the ancillary services may

increase, and could be used to strongly limit the consequences of the RES

penetration on the thermal plants.

- Finalize the implementation of the AGC on the SIC and SING (in progress)

- Maintain a good level of knowledge within the TSO staff regarding conventional power

plants processes:

Since TSO is in charge to verifying plant performance regarding provision of

ancillaries, it is recommended that the TSO has intermediate knowledge about

conventional power plant processes and operation. A sufficient level of knowledge is

necessary to support the successful implementation of some of the above

recommendations (definition of services, third-party verifications, use of models, etc.),

with an attention point on flexibility.

- Use penalties for imbalances as incentive for improvement

Penalties for imbalances can be a good driver to push the assets to work on

continuous improvement of their reliability and reactivity for the required grid support.

Penalties for power shortage (lower than the grid set point) should in principle be

lower than penalties for power excess (higher than the grid set point). Cancellation of

the penalties could even be considered if the plant imbalance “helps” the grid to

correct the overall imbalance (cf. system in Belgium).

IV/ Make sure the new plants are in line with best practices

Considering the ambitious targets of Chile for the development of RES (wind and

solar could represent as much as 40% of the energy mix by 2050), the new plants

should already anticipate the future needs for flexibility. The current grid situation or

an ancillary market (if put in place) may not give enough incentives. In Europe, some

plants built in the late 2000’s were still designed for base load operation whereas the

need for flexibility was already forecasted by many observers.


Separate requirements should be imposed to new Rankine cycles, CCGT and OCGT.

In ELL opinion, these should mainly cover the turndown, start-up times and ramp

rates.

Some pieces of equipment are difficult to install in retrofits and should be foreseen

from the beginning. For example, it is now good practice to install a by-pass stack in

the design of new CCGTs (ex. Kelar) or to foresee a spare space for the OCGTs and

CCGTs for the installation of a SCR, in case the NOx emission limit are further

reduced.

International benchmarks, literature or OEM publications could be used to define

minimum technical requirements. The performances of the European fleet (mostly

existing units which were made flexible with retrofits and upgrades) could be a basis

of comparison.

As the plants also depend on the OEM technologies, deviations from the minimum

requirements may exist. The authorities may ask the plant developer to justify those

deviations by independent parties and/or an official report from the OEM. If several

projects are competing, the non-fulfilment of the flexibility requirements could be

addressed with a multi-criteria score evaluation (plants not fulfilling the minimum

requirements would receive a “0” score for those specific criteria).

V/ Foresee enough flexibility in the definition of emission levels

The emissions of the plants in transient modes (including start/stop) or at low load

can be much higher than for the “normal” operating conditions. Besides, the decrease

of the emissions is not easy to implement on existing plants or requires large

investments (e.g. SCR) which may not always be possible. Hence, this point should

be analysed carefully by the environmental authorities with the possible evolution of

the plant operating regime with the penetration of RES.

Enough flexibility should be considered in the definition of the emission limit values

and their application.

For example, less strict emission limit values can be applied in specific operating

modes (low load). Averaging the concentration limits on longer periods of time can

also give more latitude to the plants while keeping a maximum emission threshold.

6.2. Measures applicable if an ancillary service market is put in

place

VI/ Introduce incentives for ancillary services

The evolution of the flexibility in Europe was mainly driven by the market, resulting

from the lack of profitability of the thermal plants combined with the additional

revenues plant could obtain on the ancillary service market. The Chilean system is

different from the dispatching point of view but ELL strongly believes that more

incentives should be given to the plants towards flexibility (i.a. with a specific

remuneration for ancillary services).

An incentive system would also limit the audits required for the verification of the

detailed technical parameters by the TSO. With clear high level contracts and


incentives, the plant would more “naturally” improve their technical performances to

get additional revenues.

The authors recognize that the financing of such market should be evaluated with

care in order to avoid / limit the overall increase of the system costs (i.e. the energy

price for the final customer). A shift of (part of) the current capacity payment to

ancillary services payment would be an ideal solution. Nevertheless, an increase of

the overall system costs due to the integration of the RES is also likely (its estimation

is currently a “hot” topic in many countries).

The definition of a “strike price” (i.e. maximum energy price in addition to the capacity

payment) as currently discussed for the new capacity payment mechanism in Italy

may also be a possibility to limit the costs of the current capacity payment scheme in

Chile.

- Bidding on PFC reserve

[13] indicates that the decrease of the spinning reserve will impose a distribution of

the PFC reserve on all thermal units (i.e. de-rating from Pmax). The verification of this

statement is beyond the scope of the current study.

Another approach would be to define the minimum number of units required for the

stability of the system and combine it with a “bidding” scheme for the PFC contribution

(capacity payment in CLP/MW) on standard products. The bids should be given by

the plants as a function of the set point received from the central dispatch for the

conventional “energy supply” (which they do not control). The grid would dispatch the

required VFR with a merit order based on the bids.

The most flexible units would be capable to offer more power in MW (compliant with

the requirements of the product) and get more capacity payments, which creates the

incentive.

Separate products could be foreseen to integrate the participation of the coal plants

(less flexible but their capacity payment may be cheaper) or DSM.

- Bidding on SFC reserve

Bids on SFC could be implemented even if the VFR is distributed on all running units.

The bidding system would be very similar to the one proposed for the PFC. Each

plant could make a bid, depending on the load set point received from the central

dispatch for the conventional “energy supply”. The plant operators could even provide

bids with the sum of the capacity available for PFC and SFC (system implemented in

Belgium) in order to make the comparison easier for the TSO.

The most flexible units would be capable to offer more MW (compliant with the

requirements of the product) and get more capacity payments, which creates the

incentive.

A specific product (with longer times for power supply, hence lower ramp rates) could

be foreseen to integrate the coal plants.

The bidding scheme could also foresee the possibility of starting-up a plant which is

not selected for the conventional energy supply in order to support the grid. In

Belgium, at specific times of the year, the SFC is provided by one CCGT which is not


profitable solely on the energy market (the plant only runs thanks to the supply of

ancillary services).

- Bidding on TFC reserve

The TFC management makes part of the central dispatching in the current scheme

(cheapest unit considering the start-up and marginal costs).

A specific capacity payment could be foreseen for the plants fulfilling TFC criteria (e.g.

start-up less than xx min, fast or “standard” TFC) in order to give an incentive to the

plants to reduce their start-up time.

6.3. Measures applicable if an energy market (decentralized

dispatching) is put in place

Europe made the choice of a fully decentralized dispatching with minimum

intervention of the TSO on the energy market. This follows the decision to create a

continental energy market, as formalized in the successive liberalisation directives.

From a technical point of view, this system certainly increased the flexibility of the

power plants in a simultaneous context of overcapacity, high competition and reduced

profitability. However, for many observers, the current situation is not sustainable as

the market puts a huge pressure on the profitability of the European utility companies,

does not promote new investments and creates volatility. One of the consequences

is the development of new capacity payment schemes by many European countries.

The recommendations made in the previous sections are generally applicable to a

liberalized market as well. A few additional ideas are briefly18 developed hereunder

based on the Belgian and Italian examples.

- Creation of an Energy market (Day Ahead followed by the Intraday)

The implementation of an energy market is also an incentive for plant flexibility as the

latter can help them to catch market opportunities (peak prices, shifting modes, etc.).

Nevertheless, the following return of experience of the European case should be

considered:

o The market often fails to take into account properly the risk of black-out and

may increase the volatility of the prices.

o It does not always give the right price signals for the long term adequacy of

the power system and the investments to the future needs.

o The integration of the subsidized RES strongly biased the market for the

thermal plants with their quasi-zero marginal costs (2 combined effects

occur: decrease of the load factors and decrease of the wholesale energy

prices).

- Pooling of plants

18 ELL understanding is that the change of the centralized dispatching system is currently not considered as an option for the evolution of the grid management in Chile.


The system of ARPs (as in Belgium) can be a way to keep a limited number of actors

in charge of the balancing of the grid. It could be a first step in case of liberalization

of the dispatching, even though it gives more “power” to the selected ARPs.

- Essential plants

In a fully free market, the plants should normally be allowed to decide if they are

dispatched. In congested area, power plants could abuse their position and create

power shortages on purpose to increase their profits. The system of “essential plants”

implemented in Italy in combination with battery storage could be an example to

mitigate this issue.

- Capacity markets

The system implemented in Italy fixes a “strike price” and obliges the plants to make bids on

the energy / ancillary markets. This is a way to limit the profits on the energy market of the

plants which receive capacity payments.


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Overview of Chilean Thermal Fleet

1. Distribution of the technologies and fuels used in the SING and the SIC

The market share for Rankine cycles units is more important in the North (SING) than in the

center of the country (SIC).

Most of the Rankine cycles use coal as primary fuel. Some units can also burn petcoke and

biomass. Old units using fuel oil / diesel are used for cold reserve only (namely, Renca 1 &

2 and Laguna Verde 1 & 2).

Nearly all the CCGTs in Chile use natural gas as primary fuel, with the exception of Gas

Atacama, since the power plant is not supplied in gas for the moment, and only operate with

diesel. Nearly all the CCGT units are dual-fuel and can either burn natural gas or diesel.

About 95% of the OCGTs are connected to the SIC. A quarter of the entire fleet of OCGTs

operates with natural gas, the others with diesel. Most of the OCGTs are peaking units, and

operate a few hours during the year.

Figure 69: Distribution of the types of technologies in the SIC and the SING

1188 MW

772 MW

126 MW

2723 MW

Installed Capacity – Thermal - SING - 2016

CCGT - Gas

CCGT - Diesel

OCGT - Diesel

Rankine - Coal

1923 MW

61 MW

619 MW

1593 MW71 MW

2570 MW

100 MW 47 MW

Installed Capacity – Thermal - SIC - 2016

CCGT - Gas

CCGT - Diesel

OCGT - Natural Gas

OCGT - Diesel

OCGT - CHP Natural Gas

Rankine - Coal

Rankine - Fuel Oil

Rankine - Diesel

Total: ~5GW

Total: ~7GW


2. Rankine cycles

Figure 70: Rankine cycle - Age distribution

The fleet of Rankine units is relatively new: Half of the Rankine assets are less than 8 years-

old, and the first quantile is less than 5 years old. Besides, some Rankine cycles are still

under construction in the country (s.a. the IEM project in the North).

All the installation are subcritical units. Power output are relatively low compared to

international references, ranging between less than 100 MW for the oldest units (Laguna

Verde 1 & 2, Renca 1 & 2, Tocopilla U12 and U13) to a maximum of 350 MW (Santa Maria,

Bocamina 2).

CTA and CTH are the two only fluidized-bed type in Chile, the other Rankine units of the

fleet are PC-type. Besides, CTA and CTH can be partially fuelled with biomass.

Laguna Verde 1 & 2 and Renca 1 & 2 are really old assets. They operate with expensive

light fuel / diesel and are almost never running. They are dedicated to cold reserve.

With exception of these four units, all the Rankine units are equipped with end-of-pipe flue

gas treatment devices for DeSOx, including:

■ Wet (Guacolda 3 for ex.)

■ Semi-wet (Nueva Tocopilla for ex.)

■ Seawater (Santa Maria and Ventanas)

■ Dry systems (Tocopilla U12, U13, U14 and U15 for ex.)

For CTA and CTH, the desulfurization is performed with directly direct injection of limestone

in the fluidized-bed.

Some power plants are equipped with FFs, others with ESPs for the capture of fine particles.

All the new units come with a SCR for the DeNOx process (for ex. IEM, or Guacolda 5).

Several units share a common chimney, with a single CEMS to declare the emissions to the

authorities (ex. CTM1 together with CTM2, or Tocopilla U14 together with U15).


A large majority of the Rankine assets were built near to the Pacific Ocean. As such, nearly

all the Rankine plants are cooled with seawater, through a once-through condenser. There

are two exceptions:

■ Renca 1 & 2 which is installed inland, in the region of Santiago where mechanical-

draught cooling tower are installed

■ Cochrane 1 & 2 which operate with an hybrid cooling system

3. CCGTs

Figure 71: CCGTs - Age distribution

The fleet of CCGTs in Chile is older than the Rankine fleet. Half of the CCGTs are less than

17 years-old, and the first quantile is less than 10.5 years-old. Kelar is about to enter in

operation in CC mode.

Gas Atacama 1 & 2 and Kelar are in 2+2+1 configuration (2 GTs, 2 HRSGs and 1 ST). All

the other CCGTs are in 1+1+1 configuration.

San Isidro 1 & 2, Gas Atacama 1 & 2, Nehuenco 2 and the Kelar project are equipped with

a bypass stack and are capable to operate in both OC and CC mode.

In general, CCGTs in Chile are dual-fuel, using natural gas as primary fuel and diesel as

secondary fuel, when natural gas is not available. Exception is made for the power plant of

Yungay U4 (61 MW) which only operates with diesel. Also, Gas Atacama is not supplied in

gas for the moment.

Nueva Renca, San Isidro 1 & 2, Nehuenco 1 & 2, and Yungay U4 are cooled with a

mechanical-draught cooling tower. The other installations are close by the Pacific Ocean

and are cooled with sea water through a once-through condenser.

4. OCGTs


Figure 72: OCGTs - Technology distribution

GE is the major provider of GTs of the Chilean fleet of OCGTs.

About half of the fleet are GE Frame 9E design. The other half of the OCGTs are smaller

GE heavy duty designs (GE Frame 6B or 5) and GTs from other turbine manufacturers (ex.

SGT-2000E from SIEMENS).

About 15% of the feet are aero derivatives design including LM6000, LM2500 and Twin Pack

FT8-C3F, mainly.

Figure 73: OCGTs - Age distribution

Half of the OCGTs are less than 11.5 years-old, and the first quantile is less than 7.5 years.

Frame 5 or eq.; 212,93

Frame 6B; 161,3108

Frame 9B; 108

Frame 9E; 1026

LM6000; 150

SGT2000E; 153

Twin Pack FT8-C3F; 158 Others; 42,5

Capacity (MW) - OCGTs


List of figures

Figures

Figure 1. Primary frequency control. See below for ΔPmax definition. 17 Figure 2. SFC Half band. The set point from the TSO is expressed in % of the half-band (α): positive

values upwards, negative values downwards. 18 Figure 3. Tertiary Frequency Control 19 Figure 4: Example of a correction factor for ambient temperature applied on the power output and the heat

rate of a GT 19 Figure 5: Definition – Gross and net active power 20 Figure 6: Definition - Pmax 20 Figure 7: Definition Pmax exceptional 21 Figure 8: Definition - Pmin 21 Figure 9: Definition – Pmin exceptional 22 Figure 10: Definition - Turndown 22 Figure 11: Definition – Derating on Pmax and uprating on Pmin 23 Figure 12: Definition - Ramp rate 23 Figure 13: Definition - Start-up process (Rankine) 24 Figure 14: Definition - Start-up process (CCGT) 24 Figure 15: Definition - Start-up process (OCGT) 25 Figure 16: Typical preparation times for a CCGT. Preparation times vary from a few dozen of minutes for a

hot start-up with the vacuum kept in the condenser to more than 10 hours for a cold start-up, after an

overhaul of the boiler (i.e. boiler dry) 26 Figure 17 – “pay-as-bid” vs “pay-as-cleared” [10]. Same average price is assumed in this illustration but it

is not the case in reality. 27 Figure 18 - "Duck curve" on the residual load for Chile in 2021 [13] 30 Figure 19 - merchant vs regulated markets (source: ENGIE – CEEME) 31 Figure 20: Example of cross-border exchanges between different power markets (source: ENTSO-E) 32 Figure 21. Active power reduction area 34 Figure 22 - ENTSO-E fault ride through requirement. Table for synchronous generator (> 110kV). 35 Figure 23. Italian Market organization 38 Figure 24 – Market zones and prices on January 12th 2017 12:00 ( [17]) 40 Figure 25. Quantification of deviation of PFC response 44 Figure 26. Energy Imbalance penalties 47 Figure 27. . Installed capacity breakdown – Belgium 49 Figure 28 - PFC products in Belgium 52 Figure 29. SFC activation requirements 54 Figure 30: Rankine cycle - Process diagram [1] 59 Figure 31: CCGT – Process Diagram ( [1] with modifications) 59 Figure 32: OCGT - Process diagram [1] 60 Figure 33: Catching more market opportunities: Examples of different typical modes of operation for power

plants 61 Figure 34 - merit order illustration 61 Figure 35 - load factor evolution 62 Figure 36 – Historical results on the Italian CCGTs in 2015 for each market. Y-axis represents the margin

after discount of the variable costs, in €/MW. X-axis represents the different CCGT units. Ancillary services

are traded on “MB” and “MSD”. “MI” and “MGP” are the energy markets (cf. section 2.3.2). Horizontal

dotted line corresponds to the average margin. [20] 63


Figure 37 - Derating on Pmax (ΔPR1) or uprating on Pmin. ΔPR1 is the difference between “Pmax” and

“Derating on Pmax” lines. Green band: possible range of power variation on de-rated Pmax due to frequency

variation (upwards / downwards). 64 Figure 38: Pmax evolution of a subcritical Rankine cycle in Poland 67 Figure 39: Pmin evolution of a subcritical Rankine cycle in Germany 68 Figure 40: Maximum ramp rates evolution of a subcritical Rankine cycle in Germany 69 Figure 41: Evolution of a warm start-up time (Rankine in Poland) and fuel consumption (Rankine in

Germany) 69 Figure 42 - Pmax evolution on a F-class CCGT 71 Figure 43 - combustion stability area and instability frequencies. “TTRF” corresponds to the turbine inlet

temperature. “Split” corresponds to the gas distribution between premix and pilot flame. 72 Figure 44 - Pmin evolution on a F-class CCGT 72 Figure 45 - ramp rate evolution of a F-class CCGT 73 Figure 46 - Start-up time (<12h shut down) and fuel consumption for a F-class CCGT 74 Figure 47 - PFC and SFC reserve evolution on 2 F-class CCGT 75 Figure 48: Definition of P10, P50 and P90 78 Figure 49: Breakdown of installed capacity by technology - SIC and SING (source: CDEC-SIC and CDEC-

SING website) 82 Figure 50. Chilean electricity market organization 83 Figure 51: Main changes in the legal framework for power plant emissions in Chile, for the past threethree

decades 90 Figure 52: Definitions of start-up processes for a Rankine cycle: According to ELL (green) and according

to the NTSyCS (pink) 93 Figure 53: Example of a start-up curve for a CCGT 93 Figure 54: Typical preparation times for a CCGT. Preparation times vary from a few dozen of minutes for a

hot start-up with the vacuum kept in the condenser to more than 10 hours for a cold start-up, after an

overhaul of the boiler (i.e. boiler dry) 94 Figure 55: Definition of P10, P50 and P90 99 Figure 56: Rankine cycles – Benchmark on turndown 100 Figure 57 : Rankine cycles – Benchmark on ramp rate 101 Figure 58: Rankine cycles – Benchmark on warm - cold start-up time 102 Figure 59: CCGTs – Benchmark on turndown 105 Figure 60: CCGTs - Benchmark on ramp rate 106 Figure 61: CCGTs - Benchmark on cold start-up time 107 Figure 62: CCGTs - Benchmark on minimum uptime 108 Figure 63: CCGTs – Benchmark on minimum downtime 109 Figure 64: OCGTs - Benchmark on relative turndown 110 Figure 65: OCGTs - Benchmark on ramp rates 111 Figure 66: OCGTs - Benchmark on start-up time 112 Figure 67: OCGTs – Benchmark on minimum uptime 113 Figure 68: OCGTs – Benchmark on minimum downtime 113 Figure 69: Distribution of the types of technologies in the SIC and the SING 127 Figure 70: Rankine cycle - Age distribution 128 Figure 71: CCGTs - Age distribution 129 Figure 72: OCGTs - Technology distribution 130 Figure 73: OCGTs - Age distribution 130

Tables

Table 1. Examples of foreseen and unforeseen changes of load and demand sides 30

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Table 2 imposed operation time for each frequency range 34 Table 3. Voltage: minimum time period without disconnecting for pu values from 110kV to 300kV 35 Table 4. Voltage: minimum time period without disconnecting for pu values from 300kV to 400kV 36 Table 5. Emission limit values for units with thermal input > 300MW th in mg/Nm³ 37 Table 6. Installed capacity breakdown - Italy 38 Table 7. Italian flexibility market summary table 48 Table 8. Belgian flexibility market summary table 57 Table 9: Emission limits for a representative fleet of thermal assets in Europe Daily compliance P10, P50

and P90 in normalized ambient conditions and O2 content 76 Table 10: Representative fleet of thermal assets in Europe, some characteristics 77 Table 11 : benchmarking of Rankine power plant performances, USC included 78 Table 12 : benchmarking of Rankine power plant performances, USC excluded 79 Table 13 : Benchmarking of CCGT power plant performances (1+1 configuration) 79 Table 14 : performance of OCGT power plant 80 Table 15. Estimation of reserve for primary frequency control – Year 2017 86 Table 16. Estimation of reserve for secondary frequency control – Year 2017 87 Table 17: Emission limit values for power plants built or declared under construction before 2011 89 Table 18: Emission limit values for power plants built or declared under construction after 2011 89 Table 19. Grid infrastructure comparison 95 Table 20. Energy market comparison 96 Table 21. Ancillary services comparison 97 Table 22: Benchmark of ELVs of NOx and CO, for OCGTs and CCGTs in normalized ambient conditions

and O2 content (15%) 114

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