Study on the Merger of the Market Areas GRTgaz Nord and Sud€¦ · Study on Merger of Market Areas...

Study on the Merger of the Market

Areas GRTgaz Nord and Sud

Final Report

By order of: GRTgaz

Submitted by: KEMA Consulting GmbH, Kurt-Schumacher-Str. 8,

53113 Bonn, Germany

Bonn, February 2012

Study on Merger of Market Areas GRT Nord and Sud Final Report 9011-666 Page - ii/125 - February 2012

© KEMA Consulting GmbH. All rights reserved.

This document contains confidential information that shall not be transmitted to any third party without written consent of KEMA Consulting GmbH. The same applies to file copying (including but not limited to electronic copies), wholly or partially. It is prohibited to change any and all versions of this document in any manner whatsoever, including but not limited to dividing it into parts. In case of a conflict between an electronic version (e.g. PDF file) and the original paper version provided by KEMA, the latter will prevail. KEMA Consulting GmbH and/or its associated companies disclaim liability for any direct, indirect, consequential or incidental damages that may result from the use of the information or data, or from the inability to use the information or data contained in this document.

Study on Merger of Market Areas GRT Nord and Sud Final Report 9011-666 Page - iii/125 - February 2012

Table of Contents

1. Executive Summary ......................................................................................................... 1

2. Introduction ...................................................................................................................... 7

3. Definition and Qualification of Physical Congestion Scenarios ........................................ 9

3.1 Introduction ...................................................................................................... 9

3.2 Future Network Infrastructure and Relevant Physical Constraints .................. 9

3.3 Market Simulations: Methodology and Assumptions ..................................... 16

3.4 Assessment of Physical Congestion .............................................................. 19

3.5 Summary of Findings ..................................................................................... 33

4. Identification and Assessment of Potential Mechanisms for Congestion

Management .................................................................................................................. 35

4.1 Introduction .................................................................................................... 35

4.2 Description of Potential Mechanisms ............................................................. 35

4.3 Objectives and Assessment Criteria .............................................................. 51

4.4 Qualitative Evaluation .................................................................................... 55

4.5 Summary of Findings and Initial Conclusions ................................................ 69

5. Evaluation of Options for Congestion Management after the Market Merger ................ 74

5.1 Introduction .................................................................................................... 74

5.2 Physical Options for Mitigating Congestion in North-South Direction ............ 74

5.3 Approaches for Mitigating Congestion in North-South Direction .................... 87

5.4 Congestion in South-North Direction ............................................................. 95

5.5 Congestion in West-East Direction ................................................................ 97

5.6 Cost Assessment ........................................................................................... 98

5.7 Summary and Recommended Options ........................................................ 107

6. Recommendations ....................................................................................................... 111

6.1 Proposed Measures for Enabling the Market Merger .................................. 111

6.2 Proposed Steps towards Preparation of the Market Merger ........................ 120

7. Appendices .................................................................................................................. 125

7.1 Annex 1: Relevant Physical Constraints ...................................................... 125

7.2 Annex 2: Summary of Market-Based Assumptions ..................................... 125

Study on Merger of Market Areas GRT Nord and Sud Final Report 9011-666 Page - iv/125 - February 2012

Table of Figures

Figure 1: Overview of proposed measures to enable the market merger 3

Figure 2: Overall structure of activities within this study 8

Figure 3: Assumptions on firm entry/exit capacities in the joint GRTgaz area in 2016 11

Figure 4: Main bottlenecks and conditions for congestion from North to South 13

Figure 5: Main bottlenecks and conditions for congestion from South to North 14

Figure 6: Main bottlenecks and conditions for West-East congestion 15

Figure 7: Temperature dependence of constraints on inequations for physical congestion

in West-East direction 16

Figure 8: Principal structure of the simplified gas market model 17

Figure 9: Aggregated supply (gross) to the GRTgaz area in scenario 1 20

Figure 10: Exit flows to TIGF and Switzerland in scenario 1 21





Figure 15: Degree of congestion in North-South direction (scenarios 1 to 3) 26

Figure 16: Congestion duration curves in North-South direction (scenarios 1 to 3) 27

Figure 17: Degree of congestion in South-North direction (scenarios 1 to 3) 28

Figure 18: Sensitivity of condition SN-4a (South-North) to low temperatures 30

Figure 19: Degree of congestion in West-East direction (scenarios 1 to 3) 31

Figure 20: Requirements on congestion management mechanisms in relation to the

impact and frequency of congestion 70

Figure 21: Schematic clustering of different congestion management mechanisms to

different types of physical congestion. 72

Figure 22: Reduction of physical congestion in North-South direction in the 'non-

conservative case' in scenario 1 76

Figure 23: Daily output of CCGT plants between mid April and mid October 78

Figure 24: Comparison between climatic capacity (red) and simulated operation (blue) of

underground storages in the GRTgaz area 80

Figure 25: Exit flow to TIGF in the non-conservative scenario 83

Figure 26: Decrease of N-S congestion due to impact of storages and CCGT 86

Figure 27: Impact of storages and CCGT on congestion from North to South (non-

conservative scenario) 87

Figure 28: Decreased congestion at reduced exit capacity to TIGF (300 GWh/d) 89

Figure 29: Duration curves for North-South congestion under different assumptions on

the availability of exit capacity to TIGF / Spain 91

Figure 30: Congestion in South-North direction in scenario 2 (low Take-or-Pay) 95

Study on Merger of Market Areas GRT Nord and Sud Final Report 9011-666 Page - v/125 - February 2012

Figure 31: Development of different spot indices 2009 – 2011 101

Figure 32: Opportunity costs for delayed sales in the wholesale gas market (Zeebrugge,

2003 – 2011, delay of 1 week) 103

Figure 33: Overview of proposed measures to enable the market merger 112

Study on Merger of Market Areas GRT Nord and Sud Final Report 9011-666 Page - vi/125 - February 2012

List of Tables

Table 1: Estimated ranges of annual costs of congestion management (M€/year) 5

Table 2: Proposed steps towards implementation of recommended measures 6

Table 3: Outline of main development scenarios considered for congestion analysis 19

Table 4: Impact of sensitivity runs on congestion in North-South direction 33

Table 5: Overview of potential mechanisms for congestion management 36

Table 6: Clustering of potential mechanisms for congestion management 37

Table 7: Criteria for evaluation of potential mechanisms for congestion management 51

Table 8: Evaluation of interventions outside normal operating conditions 56

Table 9: Evaluation of interruptible capacities (unbooked capacity) 58

Table 10: Evaluation of locational restrictions 60

Table 11: Evaluation of capacity buy-back 61

Table 12: Evaluation of locational trades 63

Table 13: Evaluation of flow commitments 64

Table 14: Evaluation of TSO-contracted storage 66

Table 15: Evaluation of locational swaps 67

Table 16: Evaluation of swaps between neighboring TSOs 68

Table 17: Evaluation of re-routing gas flows through neighboring networks 69

Table 18: Potential reduction of N-S congestion due to actual CCGT operating pattern 79

Table 19: Excess summer injection capacity at storages relevant for condition 1a 81

Table 20: Theoretical potential for relieving congestion from North to South (GWh/d) 85

Table 21: Assumed requirements for market-based congestion management in North-

South direction 99

Table 22: Summary of cost estimates for actions at Fos (N-S congestion, scenario 1) 102

Table 23: Probability of significant price declines over a period of one week at selected

hubs in North-Western Europe 104

Table 24: Potential costs of South-North congestion (0.5 TWh/a) 104

Table 25: Estimated ranges of overall cost for congestion management in different

scenarios 109

Table 26: Required steps towards implementation of recommended measures 121

Table 27: Tentative roadmap for implementation of recommended measures 124

Study on Merger of Market Areas GRT Nord and Sud Final Report 9011-666 Page - 1/125 - February 2012

1. Executive Summary

GRTgaz is currently investigating different ways for enabling a complete merger of its current

market areas, GRTgaz North and South, without having to undertake all investments which

would be required to avoid all physical congestion in a single market area. Within the context

of this overall initiative, and at the request of the CRE, this study specifically looks at poten-

tial options for managing congestion by means of contractual and/or market-based arrange-

ments. The overall aim of corresponding measures is to manage congestion which may oc-

cur as a result of excessive flows between different parts of the single, enlarged market

area, within the framework of a competitive gas market and with minimum interference to the

commercial operations of shippers.

The choice of such measures among others depends on the nature of congestion and on the

existing (or expected) flow patterns. In the first part of this study, we have therefore applied a

simplified model of the French gas market, in order to quantify the potential risk of conges-

tion in terms of frequency and severity. To provide for a comprehensive and robust analysis,

the simulations have covered three different scenarios, which have been developed with the

aim of representing fundamentally different developments of the French, European and

worldwide gas markets for the time horizon 2016 to 2020.

The simulations have shown that congestion will remain infrequent and of limited scope in

two of the three scenarios considered. Nevertheless, there are specific issues, such as po-

tential congestion from South to North at periods of extreme cold spells. Most importantly,

there is significant risk of structural congestion from the North to the South of the GRTgaz

network in situations with high prices for LNG imports. Under these circumstances, and de-

pending on the detailed assumptions, the GRTgaz network may encounter structural con-

gestion in the summer season, with daily congestion reaching up to 300 to 500 GWh/d. This

finding has been confirmed by various sensitivity runs that reflect a wide range of different

assumptions. In general, however, the probability and impact of congestion is highly sensi-

tive to future exchanges of natural gas with Spain, as potential exports to Spain might se-

riously aggravate physical congestion from the North to the South.

Despite a limited probability and degree of congestion in general, there is a signifi-

cant risk of structural congestion from the North to the South of the GRTgaz network

in certain situations, with a high sensitivity to future exchange patterns with Spain.


With regards to potential approaches for congestion management, we have analyzed a wide

range of different instruments, including market-based mechanisms as well as others that

rely on mandated restrictions for shippers. Similarly, we have considered options that involve

interactions with other infrastructure operators, as well as mechanisms related to commodity

trading or entry / exit capacity rights. These mechanisms have been assessed against a

structured set of criteria, which had been previously discussed and agreed with GRTgaz, the

CRE, the French Ministry of Industry and a wider group of stakeholders in the framework of

the Concertation Gaz.

None of the mechanisms is clearly superior to the others with regards to the entirety of these

evaluation criteria. In order to promote economic efficiency and the development of a liquid

and competitive gas market, we recommend that market-based mechanisms should be con-

sidered the preferred solution. However, with the potential exception of flow commitments,

market-based mechanisms are not able to ensure a guaranteed reliability of the network in

all possible situations, or not within reasonable costs. It therefore seems useful to consider

the application of additional back-up solutions in the form of administrated solutions, in order

to ensure the physical integrity of the network in all situations.

Market-based mechanisms should be considered the preferred solution but may

need to be supplemented by administrated measures to guarantee network integrity.

Our analysis shows that all types of congestion can generally be managed by sufficient vo-

lumes of flexibility. In combination with the regional distribution of different sources, available

flexibility in the French gas market seems to be sufficient to enable the application of market-

based mechanisms in most situations. Most importantly, we note that GRTgaz does not

seem to depend on any single source for relieving congestion under normal circumstances.

In addition, temporary variations in the geographical distribution of injections into and with-

drawals from underground storages may provide a very effective way of at least temporarily

relieving network constraints.

Despite this generally optimistic view, it is important to note that most critical situations are

linked to entry/exit flows at a few specific locations, namely Fos, TIGF and, to some extent,

Montoir. In the case of structural congestion from North to South in particular, a simultane-

ous and coordinated use of multiple instruments at several locations should thus be consi-

dered as an essential precondition for successfully managing congestion by market-based

mechanisms.


GRTgaz generally has access to sufficient volumes of flexibility,

which can be expected to enable the use of market-based mechanisms.

However, the situation in the South of France requires attention.

In order to promote economic efficiency, and in line with the general evaluation of different

congestion management mechanisms above, we propose that physical congestion should

primarily be managed by market mechanisms. We suggest that the main tool in this respect

should be short-term instruments, such as locational trades and/or capacity buy-back, which

should be used to deal with congestion on a day-to-day basis. Due to a significant risk of

structural congestion in one of the scenarios, we strongly recommend to complement this

short-term instrument by an additional medium-term market mechanism.

This medium-term market mechanism should take the form of, for instance, monthly tenders

to procure flow commitments at Fos and/or purchase back exit capacity to TIGF from ship-

pers. Whilst also being based on market principles, this additional instrument should primari-

ly serve to ensure the availability of sufficient flexibility in the short-term, which is an essen-

tial precondition for maintaining network integrity on a day-to-day basis even in the presence

of structural congestion. Consequently, this additional instrument would be required in spe-

cific situations with the risk of insufficient volumes of gas being available at Fos at times of

structural congestion from the North to the South.

Figure 1: Overview of proposed measures to enable the market merger

Other supplementary measures

Direct interventions

(measure of last resort)

Flexibility available through

cooperation with other TSOs

Medium-term

market mechanism

Short-term

market mechanism

(Locational storage swaps, conversion

of firm to interruptible capacity)

Potential supporting mechanisms


To limit the costs of congestion management and to make optimal use of the flexibility avail-

able to the system, we furthermore recommend considering the application of two supporting

mechanisms, namely:

Conversion of firm exit capacity to TIGF to interruptible capacity; and

Enabling of locational storage swaps through a revision of storage bundles.

First, our analysis has shown that the conversion of unsold exit capacity to TIGF from firm to

interruptible capacity might provide a very effective instrument for managing congestion at

limited costs, without interfering with the existing contractual arrangements of shippers. The

potential application of this instrument would however have to be weighted against its impact

on other over-arching objectives and criteria, such as the level of market integration between

GRTgaz and TIGF, or the market situation in the TIGF area. Secondly, a revision of the cur-

rent storage groups into a single set of standardized storage products that only differ by their

technical capabilities but not by location, may simplify the interactions between Storengy and

shippers. Even more importantly, it may enable the application of locational storage swaps,

which would provide a highly effective instrument for the temporary resolution of congestion

from North to South.

To increase the robustness of the proposed approach to extreme events, and to facilitate the

use of other inherent sources of flexibility in the gas network, we finally recommend that the

core mechanisms proposed above are enhanced by two supplementary measures:

First, GRTgaz should actively explore the scope for an increased use of other tools,

such as the re-routing of flows or TSO-to-TSO swaps; both options may require the

revision of existing or the development of new operating agreements between

GRTgaz and other infrastructure operators; and

As a measure of last resort, the TSO should be entitled to directly intervene in the

market if there are no other means to relieve congestion; despite their distorting ef-

fects in individual cases, this may be preferable to the risk of serious threats to net-

work integrity of excessive costs or expensive back-up solutions.

In order to assess the costs of congestion, the flexibility available at different sources has

been priced based on the proposed mechanisms, recent experience and assumptions on the

future development. In combination with the quantitative analysis of physical congestion, this

has allowed us to estimate the total annual costs of congestion management in different

scenarios and under different assumptions.

As illustrated by Table 1, annual costs of congestion management may vary considerably.

Whilst they are largely negligible in some cases, they may amount to more than € 85 to 170


million in other years, partially depending on the mechanisms used to deal with congestion.

These wide ranges essentially reflect the major degree of uncertainty on the future develop-

ment of the French, European and worldwide gas markets, which cannot be predicted with

certainty. On average, the costs of congestion management can be expected to be signifi-

cantly smaller than indicated by the upper estimates in Table 1, since these values relate to

specific cases which are not necessarily representative of the average development over

multiple years.

Scenario 1 Scenario 2 Scenario 3

Congestion

pattern Base Case

Alternative

Case(a)

Normal / Warm

year

Cold

year

North-South 76.5 - 170 38 - 85 - - -

South-North - - - 5 - 20 -

West-East - - - - -

Total 76.5 - 170 38 - 85 - 5 - 20 -

Table 1: Estimated ranges of annual costs of congestion management (M€/year)

(a) – Based on use of interruptible capacities to TIGF, but without consideration of the asso-

ciated (opportunity) costs

Please refer to section 5.6 for details

Before detailed decisions are made on the implementation of individual mechanisms, it

seems useful to further explore the feasibility and potential application of each instrument

and to discuss the detailed design options with all relevant stakeholders. As a final output of

this study, Table 2 therefore summarizes a list of issues to be considered and proposed

steps towards implementation of the recommended measures.


Measure Required actions

Locational trades

Develop necessary product specifications, rules and contractual

agreements

Identify and agree with suitable market operator (Powernext?) for

establishment of required trading platform or, preferably, integra-

tion into existing organized market

Monthly tenders

Investigate feasibility of necessary modifications to current rules

for the use of LNG terminals at Fos

Consult with stakeholders on suitable products, timelines and ne-

cessary / acceptable restrictions

Develop necessary product specification, rules and contractual

agreements

Conversion of firm to

interruptible capacity

Discuss and decide on application of this option

Agree on remuneration for TIGF (if relevant)

Revision of storage

bundles and locational

storage swaps

Investigate possible / optimal scheme (Storengy, GRTgaz)

Check feasibility and prepare revision of product definitions, exist-

ing contracts and capacity reservations etc.

Discuss and agree on applicable possibilities, limitation, rules and

procedures between Storengy and GRTgaz

Development / revision

of operating agreements

Review / develop operating agreements with other infrastructure

operators

Direct interventions (as

measure of last resort)

Review definition of ‘normal operating conditions’ and conse-

quences for network being operated outside these conditions

Other Ensure that GRTgaz has necessary procedures in place to proper-

ly analyze and forecast risk of future congestion

Table 2: Proposed steps towards implementation of recommended measures


2. Introduction

In recent years, GRTgaz has taken a number of important steps towards providing the foun-

dation for a competitive market for natural gas in France. Among others, this has included a

reduction in the number of market areas for high calorific gas from four in 2005 to two today.

Nevertheless, it is the explicit objective of GRTgaz and the CRE to establish a single market

area that would cover the entire network of GRTgaz, if this is possible.

The option of enabling a complete merger of the two market areas through investments into

the grid has been rejected for the time being due to the associated costs. In 2009, GRTgaz

also investigated the alternative of managing physical congestion solely through a set of

contractual mechanisms, such as flow commitments. At that time, however, this approach

was also discarded due to its complexity and costs.

In the meantime, GRTgaz has engaged in a major investment program, which will be com-

pleted by 2016 and which will help to reduce potential congestion significantly. Following the

completion of the corresponding projects, the scope for achieving market integration through

contractual arrangements may change. At the request of the CRE, GRTgaz has therefore

decided to commit itself to initiate this study, which assesses the feasibility of creating a sin-

gle market where residual physical congestion is managed by a set of appropriate contrac-

tual and administrated measures.

In line with this general scope, the current study serves to identify and assess potential op-

tions for managing physical congestion in a joint market area, without endangering the inte-

grity of the network. This work builds upon a comprehensive quantitative assessment of the

frequency and extent of physical congestion. It is supplemented by a qualitative assessment

of a range of potential mechanisms which may be used to resolve or at least relieve physical

congestion. Based on this analysis, this study subsequently considers the application of

selected mechanisms which may help to mitigate the physical congestion identified before.

Finally, this study recommends a set of mechanisms which serve to enable and facilitate the

successful merger of the two market areas into a single zone.

The analysis under this study has been supported by additional technical analysis carried

out by GRTgaz and checked by KEMA. This additional analysis aimed at developing robust

assumptions on the future state of the network, as well as identifying and describing relevant

physical congestion patterns which may be encountered in practice. As further explained

below, the outcome of this analysis then provided the necessary input for part of the quantit-

ative assessment within the framework of this study. Apart from close cooperation with


GRTgaz, this study has also benefitted from interactions with the CRE and the Ministry of

Industry, who have both been represented in the Steering Committee of this study, as well

as other stakeholders of the French gas market in the framework of the Concertation Gaz.

The overall structure of this study, which is illustrated by Figure 2, can be summarized as

follows: based on the inputs provided by GRTgaz (see section 3.2 and Appendix 1), chapter

3 serves to describe and evaluate physical congestion scenarios. The corresponding analy-

sis has made use of simplified market simulations and has considered three different market

scenarios (see section 3.3). The congestion analysis itself, as well as its main findings are

described in sections 3.4 and 3.5.

The following chapter 4 contains the qualitative assessment of the potential mechanisms

considered in this study. The outcomes of the quantitative and qualitative analysis are then

combined in Chapter 5, in order to assess detailed options for managing congestion in the

French gas market. This chapter, which effectively represents the core of this study, delivers

a set of proposals for managing the different types of physical congestion and assesses the

costs of managing congestion. Chapter 6 finally summarizes our recommendations for a set

of mechanisms which may be used to enable and facilitate the market merger, and proposes

a number of steps to be taken in preparation of the merger.

Figure 2: Overall structure of activities within this study

Physical congestion

patterns(section 3.2)

Congestion analysis

(section 3.4)

Estimation of

economic flows (section 3.3)

Scenarios for

network utilization(section 3.2)

Recommended

mechanisms(section 6)

List of

infrastructures(section 3.2)

Market assumptions

(section 3.3)

Qualitative assessment

of mechanisms(section 4)

Quantitative

assessment of mechanisms

(section 5)

Steps to be taken

(section 6)

Tasks carried out

GRTgaz

Tasks carried out

by KEMA


3. Definition and Qualification of Physical

Congestion Scenarios

3.1 Introduction

As already mentioned in the introduction (see chapter 2) GRTgaz is currently carrying out a

number of investments. These investments are expected to increase the transport capability

of the GRTgaz network significantly and to resolve internal congestion at several locations

within France. Nevertheless, it is generally accepted – and confirmed by this study - that

these reinforcements will not be able to avoid physical congestion in a combined market

area. The main focus of this chapter therefore is to assess the risk and potential impact of

physical congestion after a market merger.

In the following section 3.2, we therefore summarize the main assumptions on the future

transport capability of the French transmission network and the areas of potential physical

congestion. The corresponding information has been developed by GRTgaz such that sec-

tion 3.2 contains a condensed summary only, whilst further details are included in Annex 1

(see chapter 7.1).

In order to assess the risk and potential impact of physical congestion in different situations,

we have applied a simplified model of the French gas market. This model has been used to

simulate the physical flows into and out of the French transmission network for a number of

different market scenarios. In section 3.3, we briefly explain the structure and functioning of

the model and the main assumption for each market scenario, whilst further details can be

found in Annex 2 (chapter 7.2). Thereafter, section 3.4 presents the results of the market

simulations and assesses the frequency and scope of each of the different congestion pat-

terns identified by GRTgaz. Section 3.5 finally summarizes the main findings from this analy-

sis.

3.2 Future Network Infrastructure and Relevant Physical

Constraints

In accordance with the terms of reference, the analysis in this study is based on the ex-

pected situation in the year 2016. For this purpose, GRTgaz has developed a set of assump-

tions on the future development of the network until the year 2016 and potential congestion

patterns, which may be encountered in a combined market area. Apart from a description of

the relevant infrastructure, the former involved assumptions on the evolution of consumption


and, equally important, hypotheses on the operation of underground storages (injection in

summer and withdrawal in winter). In a second step, GRTgaz has carried out extensive net-

work simulations and analysis, in order to identify and describe physical congestion scena-

rios which could emerge in a fully merged entry/exit zone. The corresponding assumptions,

the methodology and the results of this analysis were reviewed and validated by KEMA in

the first phase of the project. In addition, individual assumptions and their impact on physical

congestion have been further checked and discussed in the course of the congestion analy-

sis performed by KEMA, which has in some cases resulted in a more detailed specification

and/or revision of the conditions describing each individual congestion.

Since this study is based on the expected situation in the year 2016 it takes into account a

number of ongoing or planned investments, including the projects Eridan, Arc de Dierrey and

Hauts de France 2 as well as the compressor stations at Cuvilly and Chazelle. These in-

vestments result in an increase of firm capacity at several entry/exit points. As a conse-

quence, the firm entry/exit capacities which have been assumed for this Study and which are

illustrated in Figure 3 are higher than current values at several locations. In this context, we

emphasize that all quantitative analysis in this chapter 3 as well as chapter 5 is based on

firm entry/exit capacities only.


Figure 3: Assumptions on firm entry/exit capacities in the joint GRTgaz area in 2016

Source: GRTgaz. "North & South zones merger. WP2 deliverable update. September 30th

2011. p. 371

Based on their analysis, GRTgaz has identified three main patterns of physical congestion,

which have been categorized as follows:

Congestion in North-South direction;

Congestion in South-North direction; and

Congestion in West-East direction.

As further explained in Annex 1 (chapter 7.1), these three major patterns combine potential

congestion along five different corridors and/or directions. For the purpose of this study,

GRTgaz has defined each congestion pattern by a set of inequations, which define the max-

imum or minimum aggregate flow at one or more entry/exit points that can be realized with-

out causing physical congestion in the network.

1 As shown in Figure 3 the entry capacity at Dunkerque has been considered as 870 GWh/d, although the actual

value may only be as high as 820 GWh/d. We have therefore verified that the daily entry flows at Dunkerque in our simulations have never exceeded a level of 820 GWh/d.

223 GWh/j

620 GWh/j

640 GWh/j

870GWh/j

370 ou 400 GWh/j

530 GWh/j

Arc de Dierrey

Hdf2

Eridan

Cuvilly

Chazelles


For example in the North-South direction, congestion is among others defined by the follow-

ing inequation:

Condition 2a Min Fos – TIGF | if TIGF > 0

Min Fos | if TIGF < 0

Where: Fos - (Net) entry flow at Fos

TIGF - (Net) exit flow at TIGF

Noting that the inequation is valid only if the net exit flow to TIGF is greater than zero.

It is furthermore important to note that most conditions are based on specific assumptions

with regards to the withdrawal of underground storage during winter and injection in the

summer. These assumptions have generally been chosen with a view to giving shippers the

full flexibility on the use of storages, i.e. to take the most pessimistic assumption such that

congestion can be relieved but in no case aggravated by a different use of storages. Con-

versely, other conditions are based on more moderate assumptions as the risk of bottle-

necks would otherwise have been too high.

In the following, we briefly present the structure of each congestion pattern as well as the

defining inequations, which are used for further analysis in section 3.4 below.

To start with, Figure 4 provides the corresponding information for congestion in the North-

South direction, which can be differentiated into congestion along a 'Western' and 'Eastern'

corridor. As indicated by the orange 'funnels' in this picture, this pattern includes a total of

four different areas of physical congestion, two of which are equivalent for both corridors.

Consequently, this congestion pattern is defined by a total of four different inequations2,

which are listed in the bottom part of Figure 4.

2 Please note that most areas of congestion are defined by a pair of two equivalent inequations. For the purpose

of the analysis in this chapter 3 it is therefore sufficient to always consider one of the inequations only.


Condition 1a: Min Montoir – TIGF + FOS

Condition 2a: Min Fos – TIGF (if TIGF > 0)

Condition 3a: Min Montoir – TIGF

Condition 4: Max Taisnières + Obergailbach - Oltingue

Entry flows: Dunkerque, Taisnières, Obergailbach, Montoir, Fos

Exit flows: Oltingue, TIGF

Figure 4: Main bottlenecks and conditions for congestion from North to South

Conditions 1a – 3a based on assumption of withdrawal of underground storage being great-

er than or equal to 50% of climatic capacity (100% for injection)

Figure 5 provides the same information for physical congestion from South to North, now

indicated by blue funnels. In this case, all relevant cases of congestion are defined by a total

of four inequations, three of which have been further considered in this study.

Obergailbach

Oltingue

FosChémery

TIGF

Montoir

Taisnières

Dunkerque

Stockage salins

Corridor ouest

Obergailbach

Oltingue

Fos

Chémery

TIGF

Montoir

Taisnières

Dunkerque

Stockage salins

Corridor est


Condition SN-1: Max Fos

Condition SN-2: Max Fos – TIGF

Condition SN-3: Max Montoir – TIGF

Condition SN-4: Max Montoir + TIGF – Fos3

Entry flows: Dunkerque, Tais-nières, Obergailbach, Montoir, Fos


Figure 5: Main bottlenecks and conditions for congestion from South to North

Conditions based on assumption of withdrawal of underground storage being equal to 100%

of climatic capacity 0% for injection (i.e. no restrictions to storage use)

Figure 6 finally shows the relation between the entry and exit flows of the French transmis-

sion grid and physical congestion in West-East direction, which can be expressed by two

different inequations.

3 Not considered in quantitative analysis

Obergailbach

Oltingue

Fos

Chémery

TIGF

Montoir

Taisnières

Dunkerque

Stockage

salins

Corridor ouest

Obergailbach

Oltingue

Fos

Chémery

TIGF

Montoir

Taisnières

Dunkerque

Stockage

salins

Corridor est


Condition OE-1: Min Fos + Obergailbach – Oltingue

Condition OE-2: Min Fos

Entry flows: Dunkerque, Taisnières, Obergailbach, Montoir, Fos


Figure 6: Main bottlenecks and conditions for West-East congestion

Conditions based on assumption of withdrawal of underground storage being greater than or

equivalent to 65% of climatic capacity and 100% for injection (i.e. no constraints on injection)

It is important to note that the corresponding inequations are based on a number of assump-

tions on daily consumption (incl. CCGTs) and the use of underground storage. These as-

sumptions need to be taken into account when interpreting the results of the congestion

analysis, as further discussed in chapter 5. One of the most important drivers in this respect

is the pattern of local consumption (excl. CCGTs) in the GRTgaz area. In each inequation

developed by GRTgaz, this effect is formulated as a function of the 'equivalent temperature'

(compare Figure 7). Consequently, the relevant constraints may change on a daily basis.

Obergailbach

Oltingue

Fos

Chémery

TIGF

Montoir

Taisnières

Dunkerque

Stockage salins


Figure 7: Temperature dependence of constraints on inequations for physical conges-

tion in West-East direction

Source: GRTgaz

3.3 Market Simulations: Methodology and Assumptions

The frequency and scope of physical congestion depend on the physical entry and exit

flows, which in turn result from the actions of shippers in the wholesale gas market. Depend-

ing on the future evolution of market prices, contractual arrangements and the liquidity of

neighboring markets, different congestion patterns may therefore occur in different situa-

tions. Since the future development of the French and foreign gas markets is unknown, the

future use of the GRTgaz grid therefore is subject to substantial uncertainty.

To nevertheless allow for a comprehensive analysis of potential congestion, we have tested

several market scenarios in a simplified model of the French gas market. As illustrated by

Figure 8, this model covers all relevant entries and exits of the French gas network4, includ-

ing the interconnections with TIGF and neighboring countries. By optimizing the use of dif-

4 In practice, the gas market model which was used for this study included a representation of the entire French

market, including the TIGF area, as well as the interconnections with Belgium, Germany, Switzerland and Spain as well as the pipe entry point at Dunkerque.

-210

-110

-10

90

190

290

-12 -7 -2 3 8 13 18 23

Equivalent temperature (in C)

Congestion Ouest EstMinimum Obergailbach + Fos

Min Fos

Min Fos +Ober-Olt

Min

imu

m f

low

(G

Wh

/day

)


ferent sources, including the use of underground storage in France, this model replicates the

operation of the wholesale gas market under the assumption of perfect competition.

Figure 8: Principal structure of the simplified gas market model

Due to the limited scope of this study, the market model has been basically refined to the

French market, which implies that it provides for a simplified representation of real life only.

To nevertheless allow for sufficiently realistic outcomes, the basic structure of the model

(e.g. the technical capability of the infrastructure or price scenarios) has been supplemented

by several additional constraints and assumptions, such as5:

Seasonal constraints on underground storage inventory levels6;

Take-or-pay obligations for pipe and LNG exports;

Penalties on an 'extreme' use of flexibility availability under long-term contracts; and

Price elasticity of foreign spot markets.

5 Please see Annex 2 for further details on some of those issues.

6 As defined by Storengy by TIGF

Storage• Capacity &

inventory

• Price (variable

component only)

Transmission• Technical

capacity

between market

areas

Input Parameters

Model Results

Cost minimization based

on linear programming

Gas Market Model

LNG• Capacity

• Price (variable

component only)

• Assumptions on

Take-or-pay

contracts

Other pipe

imports

• Capacity

• Price

• Assumptions on

Take-or-pay

contracts

Spot imports• Capacity

• Daily price

profile

• Price elasticity

Demand• Daily demand

profile

Supply• Supply by source

• Costs of supply

Costs / Prices• Daily / annual costs of

gas supply

• Impact on daily /

average market prices

Flows• Daily flows between

market areas

• Identification of

potential congestion

Storage utilisation• Daily injection and

withdrawal

• Daily inventory levels


In an initial step, the model was developed and tested against the historic use of different

sources (e.g. pipe imports, LNG, storage) and the resulting entry and exit flows in the year

2010. This exercise has shown that the results of the model broadly correspond to the pat-

terns observed in practice, despite some remaining differences especially on a daily scale.

Given that the overall objective of the simulations within this study are to study the overall

congestion patterns rather than to develop accurate forecasts, the model was therefore

found to be sufficiently robust for further analysis.

For the assessment of physical congestion in section 3.4, we have then used this model to

analyze three main development scenarios, as well as a number of additional sensitivities.

These scenarios, which have been jointly developed in discussions with GRTgaz, CRE and

market stakeholders represented in the Concertation Gaz, aim at representing a set of poss-

ible development paths, which may result in a different utilization of the French gas trans-

mission network. The main focus in this context has therefore been on differentiating be-

tween different expected flow patterns, which may be encountered in the future. At the same

time, the individual scenarios have also been designed with a view to capturing a wide range

of possible developments, such as the availability and price of pipe, spot and LNG gas, the

evolution of the European wholesale gas markets or the future contractual arrangements for

long-term import contracts.

In short, the three main scenarios can be summarized as follows (compare also Table 3):

Scenario 1: Cheap Pipe Gas

The first scenario is based on the assumption of limited LNG supplies, which are

hence relatively expensive in comparison to imports of pipe gas (from Belgium, Ger-

many and Norway). In addition, this scenario assumes the continuation of oil-indexed

prices for pipe imports, with continental European spot prices showing a seasonal

variation around the price of long-term contracts. Finally, we also assume that im-

ports from long-term contracts (incl. LNG) remain subject to substantial take-or-pay

obligations.

This scenario broadly corresponds to the current situation, with very high prices be-

ing paid for LNG in Asia. It can be deemed to reflect the possible situation in an envi-

ronment with very strong demand for LNG from Asia but limited supply.

Scenario 2: Cheap LNG gas

In contrast, the second scenario takes the opposite assumption of cheap LNG gas,

presumably due to a surplus of LNG in the Asian and Atlantic markets. Consequent-

ly, the price of LNG imports is significantly lower than for oil-indexed pipe imports,

whilst the price of continental spot gas varies between these two price levels. Again,


we assume the continuation of substantial take-or-pay obligations for both pipe and

LNG imports.

This scenario obviously reflects a situation with excess LNG supplies, in a similar

manner as experienced in recent years.

Scenario 3: Price convergence

The third scenario finally assumes a general convergence of prices for spot, pipe and

LNG gas. It can thus be thought to represent a future European market with a high

level of regional integration and competition, including for the supply of LNG.

Further details on the definition of each scenario, as well as on the underlying assumptions

with regards to prices, take-or-pay obligations and other relevant aspects can be found in

Annex 2. As indicated in Table 3, we have furthermore considered an additional sub-

scenario with reduced take-or-pay obligations for the first two scenarios.

Scenario 1

(„Cheap pipe gas“)

Scenario 2

(„Cheap LNG gas“)

Scenario 3

(„Price convergence“)

Key charac-

teristics and

assumptions

LNG traded at a premium to pipe gas

Take-or-Pay obligations for pipe gas and LNG

One variation

o Reduced Take-or-Pay obligations for LNG

Competitive pressure by cheap LNG gas


One variation

o Reduced Take-or-Pay obligations for pipe gas

Price convergence of spot, pipe and LNG gas


Table 3: Outline of main development scenarios considered for congestion analysis

3.4 Assessment of Physical Congestion

As mentioned, the three major scenarios described in the previous sections have been used

to test for potential and impact of congestion in different market environments. As a starting

point, Figure 9 shows the aggregate supply7 to the combined GRTgaz in scenario 1, both

with high and reduced take-or-pay obligations. Both results show a clear seasonal pattern,

with major purchases from the spot market in the summer but increased off-take from long-

term contracts and LNG in the winter period. Moreover, it is clearly visible that the overall off-

take of LNG is significantly lower in the scenario with reduced take-or-pay commitments.

7 Please note that the aggregate supply is expressed as a gross value, i.e. it includes potential re-exports to

Switzerland and TIGF.


Indeed, the off-take from LNG remains limited to the take-or-pay obligations in both cases.8

In summary, these results confirm the expected pattern of strong imports in the North but

limited injections in the South.

Scenario 1a: High take-or-pay obligations

Scenario 1b: Reduced take-or-pay obligations

Figure 9: Aggregated supply (gross) to the GRTgaz area in scenario 1

Figure 10 shows the resulting exchanges between the GRTgaz area, on the one side, and

TIGF and Switzerland, on the other side. In the latter case, one can observe a clear season-

al pattern, which is broadly similar to historic observations. In contrast, the exchange with the

TIGF area shows a marked difference to the past. Whilst the general pattern, with much

8 For scenario 1 with full take-or-pay obligations, simulated entry flows at Fos and Montoir broadly correspond to

average injections observed in summer 2010 and 2011.

0

500

1.000

1.500

2.000

Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar

GW

h/d

0

500

1.000

1.500

2.000


GW

h/d


higher exit flows in the summer, principally corresponds to historic flows, the flow remains

positive even during the winter period. As further discussed below, this impact is obviously

related to the additional export capacity to Spain.

Figure 10: Exit flows to TIGF and Switzerland in scenario 1

In contrast to the results for scenario 1, Figure 11 shows a very different supply pattern for

scenario 2. In this case, imports from neighboring spot markets are drastically reduced in

exchange for additional off-takes of LNG gas. In addition, we observe a strong decline of

pipe imports from long-term contracts, which are now reduced to the level of take-or-pay

obligations. A direct comparison with Figure 9 furthermore shows that the overall supply to

GRTgaz declines. Since the assumptions on local consumption are the same as in scenario

1, this observation indicates that exports to other areas (Switzerland, TIGF) are substantially

reduced. Moreover, we note that GRTgaz imports significant volumes of gas from TIGF in

the winter, or even throughout the year in the second scenario with reduced take-or-pay

obligations for pipe gas.

0

50

100

150

200

250

300

350

400

450


GW

h/d

High Take-or-pay obligations

Export to Switzerland Export to TIGF

0

50

100

150

200

250

300

350

400

450


GW

h/d

Reduced Take-or-pay obligations



Scenario 2a: High take-or-pay obligations

Scenario 2b: Reduced take-or-pay obligations


This difference is also reflected by Figure 12, which again shows the exchanges with TIGF

and Switzerland. Whilst exports to Switzerland follow a similar pattern as in scenario 1, ex-

changes with TIGF now are more similar to the status quo, with prevailing exports during the

0

500

1.000

1.500

2.000


GW

h/d

0

500

1.000

1.500

2.000


GW

h/d


summer but imports in the winter. Overall, scenario 2 thus results in a very different flow

pattern with a larger proportion of flows from the South to the North rather than a clear

North-South flow in scenario 1.


Thirdly, Figure 13 illustrates the aggregated supply for scenario 3, which is based on general

price convergence in Europe. This scenario again results in a markedly different supply pat-

tern. Imports of LNG and pipe gas from long-term contracts are relatively stable throughout

the year. Conversely, spot purchases show a high degree of volatility but remain at a rela-

tively low level overall and can now be observed throughout the year. Finally, we again ob-

serve substantial imports from TIGF during the winter.

-300

-200

-100

0

100

200

300

400


GW

h/d

High Take-or-pay obligations


-300

-200

-100

0

100

200

300


GW

h/d

Reduced Take-or-pay obligations




Similar differences can also be observed in Figure 14, which shows the resulting exchanges

with TIGF and Switzerland. Whilst exports to Switzerland are rather constant in this scenario,

the exchange with TIGF now shows a high degree of volatility. In the addition, the seasonal

pattern is much smaller than in the other two scenarios, although it is still visible.


0

500

1.000

1.500

2.000


GW

h/d

-300

-200

-100

0

100

200

300

400

500


GW

h/d



Based on these results and the inequations mentioned in Figure 4 on p. 13, Figure 15 shows

the amount of physical congestion in the North-South direction across the main scenarios.

More precisely, each curve shows the daily violation (in GWh/d) of the four relevant inequa-

tions for each of the five scenarios. For scenario 1 with reduced take-or-pay obligations for

instance, we see that inequation 1a is violated by almost 500 GWh/h for most of the sum-

mer. In other words, the sum of the entry flows at Montoir and Fos minus the exit flow to

TIGF is nearly 500 GWh/h too low during most of the summer.

In summary, Figure 15 leads to the following observations:

Scenario 1 generally results in major congestion in particular during the summer.

Whilst congestion remains limited and infrequent with regards to condition 3a (Min

Montoir – TIGF), it reaches levels of somewhere between 300 GWh/d and nearly 500

GWh/d for the other three inequations. Moreover, the latter types of congestion clear-

ly are of a structural nature. Finally, we also observe a significant degree of almost

constant congestion during the winter in case of low take-or-pay obligations.

Although congestion can also be observed for scenario 3, it remains at much lower

levels but can still reach up to 250 GWh/d on individual days. Despite a more sporad-

ic nature, congestion occurs quite frequently, i.e. for some 20% to 24% of time in

case of inequations 1a and 2a.

Finally, there is hardly any congestion in this direction in case of Scenario 2.


Figure 15: Degree of congestion in North-South direction (scenarios 1 to 3)

Note: Figure shows daily violation of congestion inequations (in GWh/d); ToP – Take-or-pay obligations

These observations are also confirmed by Figure 16, which principally shows an alternative view of Figure 15. Indeed, the congestion

duration curves clearly show the differences between the individual scenarios. In particular, we note the high degree of congestion for

0

50

100

150

200

250

300

350

400

450

500


Ph

ysic

al c

on

gest

ion

(G

Wh

/d)

Cond 1a (Min Montoir - TIGF + FOS)

0

50

100

150

200

250

300

350

400

450

500


Ph

ysic

al c

on

gest

ion

(G

Wh

/d)

Cond 2a (Mini FOS - TIGF (if positive))

0

50

100

150

200

250

300

350

400

450

500


Ph

ysic

al c

on

gest

ion

(G

Wh

/d)

Cond. 3a (Min Mon - TIGF)

0

50

100

150

200

250

300

350

400

450

500


Ph

ysic

al c

on

gest

ion

(G

Wh

/d)

Cond 4 (Max Tai + Ober - Olt)


scenario 1, which occurs on an (almost) permanent basis for condition 2a and, to a slightly lesser extent, also for condition 1a. Converse-

ly, Figure 16 also shows that is almost no congestion in scenario 2.

Figure 16: Congestion duration curves in North-South direction (scenarios 1 to 3)


0

50

100

150

200

250

300

350

400

450

500

0 50 100 150 200 250 300 350Ph

ysic

al c

on

gest

ion

(G

Wh

/d)

Days in year


0

50

100

150

200

250

300

350

400

450

500

0 50 100 150 200 250 300 350Ph

ysic

al c

on

gest

ion

(G

Wh

/d)

Days in year

Cond 2a (Mini FOS - TIGF (if positive)

0

50

100

150

200

250

300

350

400

450

500

0 50 100 150 200 250 300 350Ph

ysic

al c

on

gest

ion

(G

Wh

/d)

Days in year

Cond 3a (Min Mon - TIGF)

0

50

100

150

200

250

300

350

400

450

500

0 50 100 150 200 250 300 350Ph

ysic

al c

on

gest

ion

(G

Wh

/d)

Days in year



Figure 17: Degree of congestion in South-North direction (scenarios 1 to 3)


Next, Figure 17 shows the constraint violations in the opposite direction (South-North). Apparently, there is hardly any congestion in all

three scenarios, with the exception of a few instances of congestion according to condition SN-4a (Max Fos – TIGF + Montoir) in scenario

0

25

50

75

100

125

150


Ph

ysic

al c

on

gest

ion

(G

Wh

/d)

Cond SN-1 (Max Fos)

0

25

50

75

100

125

150


Ph

ysic

al c

on

gest

ion

(G

Wh

/d)

Cond SN-2a (Max Fos - TIGF)

0

25

50

75

100

125

150


Ph

ysic

al c

on

gest

ion

(G

Wh

/d)

Cond SN-3a (Max Mont - TIGF)

0

25

50

75

100

125

150


Ph

ysic

al c

on

gest

ion

(G

Wh

/d)

Cond SN-4a (Max Fos - TIGF + Mont)


2 with low take-or-pay obligations. On first sight, potential constraints in this direction thus do not appear to be critical. However, it is im-

portant to note that physical congestion may still reach significant amounts of more than 100 GWh/d, even if it occurs seldom.

Moreover, condition SN-4a is particularly sensitive to lower temperatures. Indeed, as illustrated by the right part of Figure 18 physical

congestion in the South-North direction coincides with temperatures of approx. -4 °C. But as the left part of Figure 18 shows the maxi-

mum allowed flow under condition SN-4a quickly decreases for temperatures below -5 °C. As a consequence, physical congestion may

become more frequent and reach (significantly) higher volumes in very cold winter periods. Although congestion in the South-North direc-

tion may therefore not be problematic in most situations, it may nevertheless become critical in certain situation, i.e. in particular during

cold spells.


Scenario 2 (low Take-or-pay obligations)

Figure 18: Sensitivity of condition SN-4a (South-North) to low temperatures

Note: Figure shows daily violation of congestion inequations (in GWh/d)

Figure 19 finally shows the degree of congestion along the West-East corridor. Again, we observe a strictly limited frequency of conges-

tion only, which is furthermore limited in terms of volumes as well. These observations indicate that this type of congestion does not ap-

pear to be critical in practice.

400

500

600

700

800

900

1.000

1.100

1.200

1.300

-10,

0

-7,5

-5,0

-2,5 0,0

2,5

5,0

7,5

10

,0

12

,5

15

,0

17

,5

20

,0

22

,5

25

,0Max

imu

m a

llo

we

d fl

ow

(GW

h/d

)

Equivalent temperature (°C)

Cond. SN-4a (Max Fos - TIGF + Fos)

-10

-5

0

5

10

15

20

25

30


Tem

pe

ratu

re (°

C)

Equivalent temperature (°C)

0

25

50

75

100

125

150


Ph

ysic

al c

on

gest

ion

(G

Wh

/d)



Figure 19: Degree of congestion in West-East direction (scenarios 1 to 3)


0

10

20

30

40

50

60


Ph

ysic

al c

on

gest

ion

(G

Wh

/d)

Cond OE-1a (Min Fos + Ober - Olt + CCGT)

0

10

20

30

40

50

60


Ph

ysic

al c

on

gest

ion

(G

Wh

/d)

Cond OE-2 (Min Fos)


In comparison, physical congestion from North to South obviously seems to be the most

critical. Apart from the basic runs, we have therefore carried out a number of additional simu-

lations for scenario 1 with slightly different assumptions, in order to test for the sensitivity of

our results to such variations. As illustrated by Table 4, the corresponding sensitivity runs

have considered different price assumptions as well as different assumptions with regards to

the use of storage, potential exchanges with Spain, or the level of take-or-pay obligations.

Besides the nature of each sensitivity run, Table 4 also indicates the general impact of each

variation on the level of physical congestion from North to South. We observe that some of

the corresponding changes do not have any tangible impact on the level and frequency of

congestion. Conversely, the complete removal of take-or-pay obligations results in increas-

ing congestion. Most importantly, however, some of the changes considered also lead to a

(significant) reduction of physical congestion.

Among others, this includes the following:

A reduction of the seasonal spread for spot gas (from 5 to 3 €/MWh) as well as a

gradual convergence of Spanish price levels with spot market prices in North-

Western Europe both result in a marked reduction of congestion. In the first case, the

positive impact remains limited (approx. 50 GWh/d) and is limited to the summer

months. Conversely, the second change leads to the disappearance of structural

congestion, although high volumes of physical congestion still occur quite often.

Secondly, a general reduction of firm capacities to the current level of long-term ca-

pacity bookings leads to significantly reduced level of congestion in summer. Con-

versely, there are hardly any tangible changes during the winter season.

Thirdly, physical congestion also decreases in case of different assumptions on the

possible exchange pattern with Spain. In both cases, congestion disappears in the

summer, even though this may lead to the advent of structural congestion in the win-

ter when a situation with imports from Spain during the summer is considered.

These observations lead to two important conclusions. On the one side, they indicate that

the observation of significant and structural congestion from North to South appears to be

robust since significant volumes of frequent or even semi-permanent congestion can be

found in many situations. On the other hand, however, the additional simulations also show

the sensitivity of the results mainly to assumptions on the future price level in Spain, or the

exchange with Spain in general.


Sensitivity Impact on congestion from North to South

Variations of price assumptions

Reduced spread seasonal spot prices Marked reduction of congestion in summer

(ca. 50 GWh/d)

Spanish spot prices = NWE spot + premium

Disappearance of structural congestion

But: High frequency and volumes remain (≥ 250 GWh/d)

Variation of Swiss price Minor variations only

Other

Variation of storage start levels and constraints Minor variations only

Reduced entry/exit capacities (a)

Reduced congestion

Exports to Spain limited to 28 TWh/a Congestion disappears in summer

"Spanish use of TIGF storage" (exports in winter, imports in summer)

Structural congestion in summer disappears

Structural congestion in winter (100 – 150 GWh/d)

No take-or-pay obligations Congestion grows up to 400 to 500 GWh

Table 4: Impact of sensitivity runs on congestion in North-South direction

(a) – Limitation of entry/exit capacity to current long-term booking for 2016, i.e. Dunkerque (250 in-

stead of 300 GWh/d), Taisnières (550/641 GWh/d), Obergailbach (500/620 GWh/d) and TIGF

(300/395 GWh/d)

3.5 Summary of Findings

Based on the analysis explained in the previous section, we conclude the following:

Our simulations show that there exists a significant risk of structural conges-

tion in the North to South direction in situations characterized by relatively

more expensive LNG. Depending on the detailed assumptions, physical conges-

tion may occur almost permanently, reaching daily volumes of up to 300 to 500

GWh/d during the summer season. This finding has been confirmed by several

additional simulations with different assumptions, such that the risk of structural

congestion can be considered as robust.

Nevertheless, based on a number of additional sensitivity runs, it appears that the

exact level and frequency of physical congestion in the North-South direction is

highly sensitive to certain variations in the underlying scenario assumptions, in-


cluding in particular on the future exchange pattern with Spain. This shows that it

may be difficult to accurately forecast the expected level of congestion.

In contrast, congestion in the South-North and West-East directions appears to be

less critical as it is limited to very few instances and limited volumes. This is par-

ticularly true for congestion from West to East, which does not exceed volumes of

some 40 to 60 GWh/d and which can be observed for a very limited amount of

time only.

Although being less critical on first sight, physical congestion from South to North

may become critical during particular cold spells in winter. Although the average

impact over many years may thus be negligible, congestion may cause substantial

problems in individual year.


4. Identification and Assessment of Potential

Mechanisms for Congestion Management

4.1 Introduction

The analysis in the previous chapter has revealed a significant risk of physical congestion in

certain situations after the intended merger of the two market areas GRTgaz Nord and

GRTgaz Sud. The corresponding findings furthermore indicate that major additional invest-

ments would be required, in order to fully resolve congestion. In line with the overall objec-

tives of this Study, the current chapter serves to identify and evaluate potential mechanisms,

which may allow resolving physical congestion even within the scope of network reinforce-

ments that are planned to be realized by 2016 (compare section 3.2 above).

As a first step, section 4.2 therefore describes a range of potential mechanisms, which may

be considered in this respect. For each mechanism, we briefly describe the underlying ratio-

nale and its principal approach and functioning. In addition, we elaborate whether there are

special requirements to be considered and provide examples of where such mechanisms

have been used in the European gas and electricity markets.

The primary objective in the context of this Study obviously is to enable the TSO to resolve

physical congestion. However, the application of such mechanisms should not result in ex-

cessive costs or lead to significant distortions of the gas market. Section 4.3 therefore sets

out several key objectives to be considered in this respect. In addition, it develops a struc-

ture set of criteria, which are then used to evaluate each individual mechanism in section

4.4. The main findings and conclusions from this analysis are then summarized in section

4.5.

4.2 Description of Potential Mechanisms

4.2.1 Overview

The analysis of potential mechanisms to resolve physical congestion in this chapter covers a

variety of different measures. These range from possible restrictions or interventions due to

a violation of the general 'normal operating conditions' to sophisticated contractual and/or


market arrangements between the TSO, on the one hand, and shippers or infrastructure

operators, on the other hand. In detail, we consider a total of ten different mechanisms as

summarized in Table 5:

Interventions outside 'normal operation conditions'

Interruptible Capacities

Locational restrictions

Capacity buy-back

Locational trades

Flow commitments

TSO-contracted storage

Locational swaps

Swaps between neighboring TSOs

Re-routing of gas flows

Table 5: Overview of potential mechanisms for congestion management

When considering these mechanisms, one can principally differentiate between two funda-

mentally different approaches. To start with, the TSO may use administrated measures to

restrict the operational flexibility of shippers or to mandate changes to the planned use of the

network. Examples include the definition of capacity products, including potential restrictions

on the use of contracted capacities within the entry/exit regime. By intervening in advance of

potential problems, the TSO can thus ensure the feasibility of all potential flows from the

beginning. Alternatively, the TSO may be entitled to intervene into the market at the stage of

the daily gas market only, for instance by rejecting nominations. It is the nature of such me-

chanisms that they are administrated by the TSO and are thus not relying on the voluntary

participation of shippers or other market parties.

KEMA considers that, in a liberalized market, preference should principally be given to mar-

ket-based mechanisms, which are based on voluntary agreements between the TSO, on

the one hand, and shippers or other infrastructure operators, on the other hand. Market-

based mechanisms aim at incentivizing shippers to avoid and/or adjust entry and/or exit

flows which (can) lead to infeasibilities, or to carry out adjustments which help to resolve the

congestion problem. In contrast to administrated measures, which may be free of charge to

the TSO, market-based generally involve a remuneration for corresponding obligations

and/or actions.

Table 6 below therefore indicates to which extent each of the individual mechanisms listed

above belongs to either the group of administrated or market-based mechanisms. In addi-

tion, Table 6 also identifies the relevant counterpart for the TSO, which is particularly rele-

vant for the case of market-based mechanisms. In principle, shippers can assess flexibility

only indirectly based on their client portfolio, their sourcing contracts or contracted LNG re-

gasification or storage capacities. In contrast, infrastructure operators, such as storage and

LNG terminal operators or neighboring TSOs, may have access to additional flexibility, which

is not available to shippers.


Apart from the difference between administrated and market-based measures, one may

alternatively also differentiate by the type of product and/or service to which each mechan-

ism is related. This is indicated by the separation between mechanisms relating to the allo-

cation and use of capacity rights (see third row) as opposed to other mechanisms that are

directly linked to the trading of commodity and/or the nominations submitted by shippers on

a daily basis (see last row).

Administrated

(mandated restrictions and

changes)

Market-Based

(based on voluntary arrangements)

Counterparty Shippers Shippers Infrastructure operators

Capacity 0. Intervention outside

Normal Operating

Conditions

1. Interruptible Capacities

2. Locational restrictions

3. Capacity buy-back

Commodity /

Nominations

4. Locational trades

5. Flow commitments

6. TSO-contracted storage

7. Locational swaps

8. TSO-to-TSO swaps

9. Re-routing flows

Table 6: Clustering of potential mechanisms for congestion management

4.2.2 Interventions Outside Normal Operating Conditions

The key responsibility of the TSO with regards to the daily operation of the wholesale gas

market is to grant and manage third-party access to the transmission grid, i.e. to realize the

transports nominated by shippers within the limits of the entry and exit capacities which have

previously been made available by the TSO to shippers. But at the same time, the TSO is

also responsible for the secure operation of the transmission system, in order to ensure safe

and reliable gas supply to all consumers.

In practice, these two obligations may sometimes conflict with each other. Namely, transmis-

sion networks have typically been designed and built for a wide range of operating condi-

tions, referred to as 'normal operating conditions' in the French market. In contrast, networks

may not be able to supply demand in some exceptional circumstances, combined with spe-

cific flow patterns, or only subject to additional restrictions on the entry and exit flows. For

example in most North Western European markets, peak demand is normally observed dur-

ing the winter months. The TSO's obligations to maintain a safe and reliable gas supply are

typically based on temperature levels that can be expected with a reasonable probability.


These temperature levels are often defined for instance based on the expected temperature

on the coldest day in 20, 50 or even 100 years. Below this temperature threshold, the TSO is

entitled to declare extreme conditions, or a "force majeure", and to actively intervene into the

market, in order to preserve or restore system integrity and to ensure essential gas supplies

to certain customer groups such as households or gas-fired power generation.

To cope with such issues, the TSO's obligations under transportation contracts are usually

limited to normal operating conditions, whilst the TSO is relieved from its normal duties vis-à-

vis shippers otherwise. Similarly, the TSO may be entitled to directly intervene into the mar-

ket and instruct certain (changes to the) flows at entry/exit points, which may include direct

control over storage and LNG terminal operations.

Congestion problems resulting from an integration of market areas may not necessarily be

covered by such a scheme. Nevertheless, it seems reasonable to expect that an integrated

market area with remaining physical constraints increases the risk of the network reaching

the limits defined by normal operating conditions. Moreover, the same approach could po-

tentially be used to deal with physical congestion, if such congestion is likely to occur very

rarely but may result in significant problems. Especially in cases where other mechanisms

fail to resolve congestion, or stringent restrictions to the flexibility of shippers under normal

operating conditions would be required otherwise, this mechanism could thus serve as a

back-up solution.

In practice, the TSO could for instance be entitled to declare a case of exceptional conges-

tion when all other mechanisms to resolve the congestion have failed, i.e. when system inte-

grity would be endangered without intervention. In this case, the TSO would be able to ad-

just shippers' nominations, i.e. to adjust, enforce or curtail flows. Depending on the scope of

the incident or the rights granted to the TSO, the TSO might also be allowed to seize control

over storage and LNG terminal operations.

The reference to normal operating conditions is widely applied in both gas and electricity

networks as system integrity has to be maintained at all times. As mentioned above, gas

transports are typically guaranteed only within design temperatures, whereas supply could

be interrupted at even colder temperatures. Conversely, in the electricity industry, extraordi-

nary curtailment and similar measures are typically limited in classical "force majeure" situa-

tions, such as network failures or major generation outages.

However, there are also examples where such measures are applied for other reasons and

in situations, which are more likely to be met in practice. For instance in the German electric-

ity market, renewable energy sources by law have priority access to the network over con-

ventional power generation. As a consequence, renewable energy sources may only be

curtailed after the TSO has exhausted all other potential instruments, including the cancella-


tion of previously accepted scheduled (nominations) or the re-dispatch of conventional gen-

eration. From the perspective of other market participants, the priority access for renewable

energy sources has thus resulted in substantial limitations to 'normal operating conditions'.

In principle, the reference to normal operating conditions can thus be regarded as a realistic

option for dealing with physical congestion after the merger of the two current market areas.

In this case, however, it would appear desirable to clearly define the corresponding condi-

tions, means as well as the consequences for different stakeholders. Apart from the condi-

tions under which the TSO may be allowed to declare the system being outside normal op-

erating conditions, this might include the rights of the TSO in such situations or a possible

sequence (or priority) of possible interventions. Additionally, the liability for any conse-

quences as well as potential reimbursement payments (if any) would have to be defined.

4.2.3 Use of Interruptible Capacities

A very basic approach to avoid physical congestion in an integrated market area could be to

reduce firm entry and exit capacities of the joint market area to a level where firmness of firm

transmission capacities can be guaranteed for all realistic scenarios. The most straightfor-

ward solution in this respect obviously is the use of interruptible capacity. I.e., capacity would

be offered to the market in the form of interruptible capacity that is fully available to the mar-

ket under normal circumstances but may be interrupted in case of physical congestion. This

would require the definition of clear and transparent criteria for interruption that reflect the

necessary changes and/or limitations in case of physical congestion. An important design

option in this respect relates to the question, whether this capacity would be combined with

other 'interruptible capacity' available at the corresponding entry or exit point (if any), or

whether it would be designated as a special category of interruptible capacity, which is less

firm than truly firm capacities but still has priority over other interruptible capacity.

A closely related option is the concept of conditional capacity9. Rather than allowing the TSO

to interrupt capacity under certain circumstances, this product is based on a definition of the

(minimum) conditions, under which shippers are available to use the corresponding capaci-

ty.10

9 Please note that the notion of conditional capacity as defined here is already used by GRTgaz, although it is

also referred to as interruptible capacity in the applicable contracts and conditions. For the sake of clarity, how-ever, we differentiate between these two closely related instruments.

10 In an ideal case, i.e. where the conditions for the (non-) availability of interruptible and conditional capacity

were known precisely, both products would thus be equivalent to each other. In practice, however, it will never be possible to exactly define the corresponding conditions without taking too conservative assumptions, such that both products differ with regards to the impact of uncertainty on shippers.


In principle, a third option could finally be to initially withhold capacity from the market but

make it available in the short term, for instance in the form of quarterly, monthly or daily ca-

pacity11. Given reduced uncertainty closer to delivery, the TSO should be able to predict the

risk (and potential impact) of physical congestion much more precisely. Consequently, it may

be possible to sell this capacity as extra capacity on a firm basis.

Interruptible capacities are widely applied in the European gas markets, in order to provide

as much capacity to the market as possible whilst maintaining the ability of the TSO to guar-

antee system integrity. Apart from normal interruptible capacity, this also includes the case

of so-called "Conditionally Firm Freely Allocable Capacity"12 in the German gas market. Si-

milarly, the concept of conditional capacities is used in several European countries, including

France. Amongst others, this includes the notion of 'climatic capacities' for entry and exit

capacity to/from the French underground storages or other conditions related to cumulative

inputs and/or off-takes at certain (groups of) entry/exit points.

Conversely, the European electricity markets provide a good example for the use of short-

term capacity to deal with uncertainty about the availability of 'firm' capacity. In most coun-

tries, cross-border capacities are allocated to the market in the form of annual, monthly and

daily capacities. Apart from a potential reservation of a minimum share of capacity for day-

ahead allocation, the volumes of monthly and especially annual capacities that are made

available to the market include partially significant margins to deal with uncertainty, such as

prolonged generation and/or network outages. For the day-ahead allocation, however, the

planned availability of the network infrastructure is taken into account13, which often results

in significant additional volumes of capacity becoming available.

In summary, the conversion of firm (long-term) capacity to interruptible, conditional or short-

term capacities certainly provides for a realistic option. Moreover, the TSO decides on the

design and volume of capacity products it wants to make available to the market. As such,

this mechanism can principally be unilaterally implemented by the TSO.

Nevertheless, in order to do so, the TSO has to have access to sufficient amounts of availa-

ble capacity, which have not yet been allocated to the market. Whilst this mechanism can

therefore be easily applied at those borders where at least some capacity has not yet been

sold to shippers, this is more difficult at entry/exit points where the available capacity is fully

booked. In the latter case, the TSO would either need the consent of current capacity hold-

ers or have to wait until existing capacity reservations expire. Alternatively, it would be ne-

11

We acknowledge that this approach may conflict with the latest draft of the draft Network Code on Capacity Allocation Mechanisms, which requires all short-term capacity to be made available in the form of quarterly prod-ucts. This issue is therefore further discussed in section 4.4.2

12 In German: "bedingt feste frei zuordenbare Kapazität"

13 Subject to some remaining reliability margins, as defined for instance by the n-1 criterion.


cessary to either mandate changes to existing capacity contracts and/or to negotiate corres-

ponding changes. In the latter case, however, this mechanism effectively becomes equiva-

lent to the option of capacity buy-back as further discussed in section 4.2.5 below.

4.2.4 Locational Restrictions

In order to increase the TSO's ability to forecast flows and to ensure the feasibility of firm

capacities, the use of capacities at certain entry/exit points could be made subject to loca-

tional restrictions. These could for instance take the form of an obligation for a simultaneous

injection and off-take (of equivalent volumes) by the same shipper for a group of two or more

entry and exit points. As such, this instrument would not necessarily have to be based on

specific pairs of points but could also use wider limits, for instance by referring to specific

parts of the overall market area. Moreover, shippers holding corresponding capacity rights

might still be allowed to nominate deviating flows, e.g. to or from the virtual point, but on an

interruptible basis only. Overall, this approach thus resembles the use of point-to-point obli-

gations within the overall framework of the decoupled entry/exit regime.

There exist various examples of locational restrictions in the European gas markets today.

For example, several German TSOs use the concept of "Dynamically Allocable Capacity"14.

In this particular case, capacities are considered firm as long as they are used for a ba-

lanced transport between specified entry and exit points. In case shippers nominate different

flow patterns, the 'unbalanced part' of the corresponding nominations becomes interruptible.

Although this approach does not directly force shippers to provide a certain load flow, it limits

the variety of flow patterns to be considered in the TSO's flow simulations and thus decreas-

es the amount of capacity which needs to be reserved for contingencies.

Similarly, in Belgium, the TSO Fluxys requires that each contract for delivery to local exit

points contains a contractual link between the supply point (exit) and the entry zone from

which that point is supplied. Shippers are free to nominate gas flows outside the stipulated

contractual link, but only at the risk of being called by the TSO to re-nominate according to

the contractual link in case of congestion.

Similar to the use of interruptible, conditional or short-term capacities as explained in the

previous section, locational restrictions are based on the definition of available capacity

products and can thus be unilaterally introduced by the TSO. Again, the use of this approach

therefore requires either the availability of sufficient unsold capacities, or the consent of

shippers for a conversion of existing capacity contracts.

14

In German: "dynamisch zuordenbare Kapazität "


4.2.5 Capacity Buy-back

Another option for resolving congestion problems on the capacity side would be a capacity

buy-back scheme. In this case, the TSO would (try to) buy back firm capacities from ship-

pers in the short-term, in order to prevent expected congestion once foreseen or to resolve

congestion once it occurs. In most cases, this mechanism would likely be based on daily

interventions. Depending on the expected duration of congestion problems, however, ca-

pacities could also be bought back for instance on a weekly or even monthly basis.

The option of capacity buy-back schemes was already mentioned in the interpretative notes

for Regulation (EC) No 1775/200515 but has also been included in ERGEG's proposals for

congestion management procedures from 200916. The latter clearly suggest the use of ten-

ders for buying back capacity in case of congestion. Alternatively, or as an initial step, the

TSO could also try to buy the required capacities from shippers on the secondary market. In

both cases, the TSO would normally buy back the required volume of capacity rights. As a

consequence, they would fall back to the TSO and could no longer be used by the market,

although they could potentially be re-offered to the market once congestion has been re-

solved.

In case congestion is expected for a prolonged period of time, the TSO could also tender for

an option contract, which gives the TSO the right to take back capacity rights at a pre-

defined strike price.17 The TSO would then exercise its right only when necessary, thereby

allowing the TSO to address potential congestion in advance, whilst minimizing the risk of

taking 'too much' capacity out of the market. This approach would bear similarities with the

concept of flow commitments as further discussed in section 4.2.7 below.

Irrespective of the approach chosen, a capacity buy-back mechanism cannot guarantee that

shippers will offer sufficient capacity to the TSO as required to resolve congestion. A less

voluntary approach could therefore be to establish an obligation on shippers to offer capacity

rights when being asked so by the TSO, potentially subject to some additional constraints on

the pricing for corresponding offers.

Capacity buy-back schemes have long been applied in the British gas market. There the

buy-back scheme is part of the strategy to incentivize the TSO to "oversell" firm capacities in

15

European Commission, Commission staff working document on capacity allocation and congestion manage-ment for access to the natural gas transmission networks regulated under Article 5 of Regulation (EC) No 1775/2005 on conditions for access to the natural gas transmission networks, SEC(2007) 822, Brussels, 12.06.2008

16 ERGEG. Congestion management procedures - Recommendations for guidelines to be adopted via a comitol-

ogy procedure. Ref: E10-GWG-67-04. 8 September 2010

17 Please note that this option effectively creates some form of interruptible capacities, but subject to a pre-

defined financial compensation for shippers in case of interruption.


order to minimize the risk of contractual congestion, whilst resolving any resulting congestion

in the short-term by buying back capacities from shippers. In practice, National Grid uses

this mechanism for selected entry capacities, and the procurement is organized as a long-

term tender with up to 42 months lead time. During the tender, shippers offer the option to

give back their capacity rights for a specified number of days during a predefined period.

Thus, the TSO is contracting an option which can be exercised in the short-term, i.e. when

required. Shippers are remunerated through a holding payment and an exercise price.

In contrast to the mechanism described so far, capacity buy-back represents a market-based

approach. It is thus based on voluntary offers by shippers and can principally be applied to

both existing and new capacity products. However, it would be necessary to establish the

detailed rules and framework for a corresponding mechanism, including the necessary pro-

cedures, rules and agreements. Moreover, shippers can be expected to request at least the

market value of capacity, which may be relatively high in case of congestion. As a conse-

quence, a capacity buy-back scheme may thus result in significant costs to the TSO at cer-

tain times. In order to provide for appropriate incentives and to avoid excessive risks for the

TSO, the regulatory treatment of buy-back costs would need to be clearly defined as well.

4.2.6 Locational Trades

All mechanisms discussed so far are related to the definition and use of capacity rights. In

contrast, locational trades are conceptually based on transactions for commodity. The under-

lying idea is that trades that are related to specific locations upstream and/or downstream of

a physical constraint will affect the flow on the congested pipeline link. The TSO can thus

use the purchase of gas upstream and/or the sale of gas downstream of the bottleneck to

reduce the nominated net flow on the critical link and reduce congestion.

It is important to note that transactions upstream and downstream of a constraint do not

necessarily have to be directly related to each other. Hence, the TSO could thus principally

engage into any combination of locational purchases upstream of the constraint and loca-

tional sales downstream of the bottleneck with one or more shippers, as long as the sum of

all trades results in a net flow against the physical congestion. In certain circumstances, it

may furthermore be sufficient to engage on one side of the constraint only, i.e. where ship-

pers are not able to re-balance their own portfolio by opposite transactions or nominations in

the same area.

In principle, locational trades are based on the exchange of commodity, involving a direct

transaction between the shipper and the TSO. Consequently, the TSO will not only have to

engage into transactions for commodity, but will also have to carry out 'counter trades' for

the same volume of commodity, in order to ensure that the overall net impact on the balance


of the gas network is zero. As an alternative, one might also structure locational trades in the

form of 'obligations to re-nominate'. In the latter case, the TSO would effectively contract for

obligations by shippers to adjust their initial nominations by a certain amount, whilst leaving it

up to each shipper to re-balance his or her own portfolio. All transactions for commodity

would thus be left to shippers, whilst the TSO would simply pay for the desired change in

nominated entry and/or exit flows in the network.

Although locational trades are not currently applied in France, this product exists in the Brit-

ish and (some of the) German balancing mechanisms. In both cases, these products effec-

tively represent an instrument for the TSO to deal with physical congestion during the day,

although they may be simultaneously used to restore the overall balance of the network.

Similar approaches are also used in most of the European electricity markets (including

France) where they are often referred to as 're-dispatch' or 'counter-trading'. In most of these

cases, the use of this instrument specifically serves to deal with physical congestion in en-

larged market areas, i.e. in order to avoid a fragmentation of the market into smaller zones.

The Norwegian electricity market represents a perfect example in this respect. Here, the

boundary of the market areas for electricity trading is regularly reviewed and adjusted where

necessary, taking into account the balance between the benefits of larger price zones for the

overall market and the costs of so-called 'counter-trading' to resolve physical congestion

within one or more of the individual price zones.

In a single market area, trades are by definition no longer related to specific locations. Sub-

sequently, for this mechanism to function in an integrated market area, specific products are

required. In order to enable the TSO to use locational trades within an integrated market

area, it would thus be necessary to establish a dedicated market platform where shippers

can offer locational products to the TSO. Alternatively, these products could be integrated for

instance into the general wholesale market or a separate balancing platform where the latter

is being used by the TSO.

Irrespective of whether locational trades are carried out in a separate market segment or

within the framework of the general wholesale or balancing market, they will need to include

a restriction on successful bidders not to nominate "against" the locational trade afterwards.

As mentioned locational trades require direct transactions between the TSO and market

parties. Consequently, it would be necessary to establish the necessary procedural and con-

tractual framework, potentially including the set-up of a separate market place or at least a

revision of existing market platforms. Similar to the case of capacity buy-back, it would fur-

thermore be necessary to clearly define the regulatory treatment of the resulting costs, in

order to protect the TSO from excessive risks whilst still providing incentives for an efficient

use of the tool.


4.2.7 Flow Commitments

Flow commitments use the commodity side of the market in order to prevent or resolve con-

gestion. In its easiest form, a flow commitment creates a commitment on shippers not to

exceed or not to fall below an agreed flow at a given entry or exit point. Alternatively, a flow

commitment may also be related to an obligation to offer an agreed change of the original

nomination, i.e. irrespective of the absolute level of the original nomination. Similar to loca-

tional trades or locational restrictions, flow commitment can be related to specific locations,

such that they can be used in a very precise way to resolve a localized congestion problem.

Flow commitments are typically tendered by the TSO for a period of a couple of months or

even a year. Shippers that are able and willing to provide such services to the TSO then

submit offers specifying the location, offered (change of) flow and the remuneration to be

paid by the TSO. The remuneration may either take the form of a fixed payment or a combi-

nation of some form of a fixed holding payment plus an additional strike price to be paid in

case the flow commitment is actually used by the TSO.

The latter is related to another design option for flow commitments:

A shipper may commit himself to always guarantee a certain flow at a specified loca-

tion, which has to be guaranteed at all times; or

Alternatively, the shipper provides the TSO with an option to request a corresponding

(change of) flow, which can be exercised at the discretion of the TSO18.

Flow commitments are widely applied in the German gas market19, both as a balancing tool

and in order to increase the level of firm capacities. The corresponding obligations are main-

ly procured through public tenders. Within the tender, shippers typically have to specify what

flow increment (upward or downward) can be supplied at which entry point, differentiating by

different time slots (e.g. months) and different temperature levels. When accepted by the

TSO, flow commitments represent call options which can be exercised by the TSO when

required. Despite the use of public tenders, German network operators provide very limited

information on the tender results, including most importantly information on the price of flow

commitments. Nevertheless, flow commitments are generally considered a rather expensive

instrument in the German gas industry and it is well known that various tenders have been

without success. Amongst others, the latter probably relates to a specific condition imposed

by the German regulator, i.e. that a capacity (i.e. holding) price may be paid to shippers only

if a first tender without capacity payments has been unsuccessful.

18

Potentially subject to some constraints for instance with regards to the frequency or the duration of such inter-ventions.

19 Referred to as 'Lastflusszusage' or LFZ


In contrast to the gas market, similar products are widely used in the European power mar-

kets, i.e. in the form of reserve contracts. These contracts, which are almost universally used

in all electricity markets that are based on bilateral trading and self scheduling, effectively

create an obligation on network users to offer a certain amount of reserves to the daily ba-

lancing mechanism. In the context of the gas market, this could for instance correspond to

an obligation to offer a certain volume of locational trades to the TSO on every day. In this

context, it is furthermore interesting to note that some of the corresponding contracts include

limitations on the price of balancing energy (i.e. commodity) to be offered on a daily basis.

Conversely, other contracts simply focus on the availability of sufficient flexibility but leave

the determination of the daily offer prices to the discretion of network users.

The use of flow commitments would obviously require the introduction of public tenders,

including the preparation of all relevant tender rules and framework agreements. Similar to

the other market-based mechanisms discussed before, it would in addition be necessary to

define the regulatory treatment of any resulting costs.

4.2.8 TSO-Contracted Storage

In section 4.2.6 above, we have discussed the option of resolving congestion by means of

counter-trading, i.e. by a pair of opposite transactions on both sides of a physical constraint.

The corresponding locational trades enable the TSO to make use of the flexibility available

to shippers or other market parties (i.e. CCGTs or interruptible customers), which are offer-

ing their capabilities to the TSO under a market mechanism. In the particular case of France,

some flexibility is furthermore provided to TSO from underground storages.

In principle, the TSO could thus enter into additional contracts for storage capacity, in order

to gain access to more flexibility. More precisely, the TSO would contract storage capacity

from storage owners, i.e. either for underground storage or, potentially, also at LNG termin-

als. This storage capacity could then be deployed freely at the TSO's discretion to balance

the network parts above and below the constraint, which would obviously include the need to

buy and sell the corresponding volumes of gas in the wholesale gas market. The amount of

storage required in terms of injection / withdrawal capacity and inventory would obviously

depend on the degree and frequency of congestion. Rather than using storage on both sides

of a constraint, an interesting option could furthermore be to simply rely on storage on one

side of the physical constraint, but restore the daily balance of the overall network for in-

stance by buying or selling the required volumes through locational trades on the other side

of the constraint.20

20

Depending on the nature of physical congestion, it might even be possible to carry out such compensatory transactions at the virtual point.


The use of storage for gas transmission and balancing is a relatively common approach,

which can be observed in various countries. To start with, GRTgaz already has access to

some storage capacity on an interruptible basis today for the purpose of daily balancing. In

Denmark, the TSO owns directly the only cavern storage and has priority access to other

underground storage facility owned by the largest incumbent DONG. Similarly, some of the

European TSOs still have direct or at least prioritized access to storage for network balanc-

ing and security of supply purposes, in particular in countries with a high degree of vertical

integration or where storage is provided on a regulated basis, such as Italy, Spain or Portug-

al.

Assuming that GRTgaz would contract for storage in the same way as shippers21, the im-

plementation of this mechanism would probably not require any substantial modifications to

the existing contractual framework. Alternatively, a separate product could be developed by

the storage operator(s) which would be specifically tailored to the needs of the TSO. To in-

crease the flexibility of this product, this may include the reservation of short-term storage

capacity, subject to availability. Unless the TSO was always using a symmetrical amount of

storage capacity both up-and downstream of a physical constraint, the TSO would finally

need to have access to locational trades or a similar mechanism. Finally, the costs for con-

tracting storage would obviously need to be included in the allowed revenue.

4.2.9 Locational Storage Swaps (in France)

Alternatively, but in effect very similar to the mechanism described before, the TSO could

also contract with storage operators to assist in the resolution of physical congestion by ad-

justing the geographical distribution of storage injections or withdrawals. As long as the net

impact of such changes is zero, this mechanism could be neutral with regards to the aggre-

gate realization of the storage use nominated by shippers, whilst still allowing the TSO to

benefit from the geographical flexibility of French underground storage.

Instead of having to explicitly contract for storage or flexibility directly and consequently

share the available capacities with the shippers, as in the previously described mechanism,

the TSO would need to engage into a separate agreement with the party or parties who are

in possession of the infrastructure and which can provide such flexibility, i.e. Storengy22. An

important precondition for this mechanism therefore is that the corresponding infrastructure

21

Potentially except for the standard obligations for a seasonal use of underground storage as defined by the 'tunnel constraints' for storage inventories.

22 Please note that a similar service could principally also be provided by Elengy. Due to the much smaller sto-

rage volume of the LNG terminals and the distributed ownership of different LNG terminals, this option might however provide less flexibility and be rather complex to handle.


operator owns and operates different storage sites that are located on both sides of the

physical constraint.

In practice, the introduction of such a scheme might be complicated by the fact that Storengy

currently offers different storage products, which are related to the physical properties of

different sites. Among others, available storage products thus always refer to just one of the

two current market areas. In a joint market area, the use of locational swaps might therefore

conflict with the individual nominations submitted by different shippers who may not own a

homogeneous set of storage capacity. One possible mitigation and/or precondition could

therefore be that Storengy creates 'bundled' storage products, which are based on a portfolio

of different storages at different places in the French gas network. Whilst this approach

would provide more flexibility to Storengy on the geographical distribution of current injec-

tions or withdrawals, it would still be necessary to ensure a regional balance over time. Con-

sequently, there may be need to offset the locational impact of storage swaps at a later time,

effectively limited this option to a temporary instrument.

Although the application of this mechanism appears to be fairly straightforward on first sight,

we are not aware of any practical examples from either the European gas or electricity mar-

kets. As such, this approach may therefore be regarded as a potentially novel instrument in

the European gas markets, which should be carefully checked before implementation.

Apart from the possible revision of current storage products, the introduction of locational

storage swaps as discussed in this section would obviously require some form of agreement

with the TSO and the relevant infrastructure operators, such as Storengy. In this context,

particular attention would need to be paid to the mutual rights and responsibilities for both

parties, potential constraints to be considered during daily operations, as well as the remu-

neration to be paid for this service by the TSO. Finally, the corresponding payments would

obviously need to be considered within the framework of the regulation of the revenues of

the TSO.

4.2.10 Swaps with Neighboring TSOs

A different form of swap may be used between GRTgaz and neighboring TSOs. For instance

to reduce a scheduled flow, which would otherwise exceed the technical limits, gas could be

swapped with a neighboring TSO, thus effectively creating a backhaul flow against the origi-

nal flow. In its effect this mechanism is very similar to counter-trading, but in this case based

on an additional exchange between two neighboring market areas rather than a simple loca-

tional swap within a single market area.

Moreover, this instrument also shares another important feature of the locational storage

swaps as explained before. Namely, given that the additional exchange between the TSOs


would either be opposite to the net nominated flow, or make use of currently unused capaci-

ty, it would be neutral to the nominations submitted by shippers. Ideally, shippers would thus

not even notice the use of corresponding swaps between two neighboring TSOs.

In principle, one can imagine two options to implement such TSO-to-TSO swaps:

1. Temporary swap – where the required volume is 'lent' by one TSO to the other for a

limited time and returned in kind at a later time, possibly in return for a service fee for

the volume and duration of the gas lease; or

2. Firm transaction – where the required volume is sold by one TSO to the other in re-

turn for a cash-out payment for the gas itself.

It is important to note that, in both cases, the participating TSOs would obviously need to

source the required flexibility locally. Depending on the physical situation of each network

and market arrangements, this may involve the use of linepack or storage, trades in the local

market (or balancing mechanism). For that reason, the remuneration to be paid by the

'requesting TSO' would therefore likely have to be based on the specific conditions and mar-

ket arrangements in each particular situation, such that it may be difficult to rely on any stan-

dardized form of remuneration. Moreover, in most cases, this instrument will only be availa-

ble on a 'best endeavors' basis, unless one or both TSOs took some additional measures to

ensure the availability of the required flexibility.

This mechanism is therefore in fact very similar to the operating balancing agreements

(OBA) that are already in place between several TSOs in the European gas markets as well

as for all entry points in H-gas in the GRTgaz network. However, OBAs are designed to deal

with steering quantities such that the resulting differences are small by definition and can be

compensated in kind rather than through financial arrangements. In addition, this instrument

is also widely employed in the US gas sector, where typically a distinction is made between

an in-kind compensation, a full cash-out or a hybrid approach somewhere in between. In

addition, TSO-to-TSO swaps are sometimes also used in the European electricity market in

the form of cross-border counter trading.

The implementation of this mechanism would require at least some form of contractual

agreement on mutual assistance between the TSOs concerned. Where OBA's are in place

even today, it might be possible to build upon on the corresponding arrangements (which

would usually need to be further developed), whereas similar solution might have to be

agreed on otherwise. As already indicated, a key issue in this respect might be the arrange-

ments for financial remuneration, which is not an issue today, as well as the regulatory

treatment of corresponding costs and revenues.


4.2.11 Re-Routing of Gas Flows

An additional form of resolving constraints by cross-border cooperation between TSOs could

be the re-routing of flows through neighboring networks. For example, in order to resolve

congestion within the French network, an import flow at the French-German border might be

reduced, assuming that there are free capacities at the Belgium-German and French-

Belgium border as well as within the Belgium and German networks respectively. In that

case, the original flow from Germany into France could be (partially) re-routed via Belgium.

Within the framework of the entry-exit system, all nominations by shippers would still be ful-

filled, although the physical flows would no longer match the nominated entry and exit flows.

However, the overall balance of each network would remain unchanged and no ownership

transfer of gas would be required.

In practical terms, the TSO experiencing congestion in its network would request such re-

routing from its neighboring TSOs. These would check whether such request could be ful-

filled and confirm the request where possible. Given that the physical balance of each net-

work remains unchanged, the costs of this mechanism would largely remain limited to the

incremental costs of compression (where relevant). Nevertheless, the re-routing of gas flows

requires unused capacities at each border, across which the corresponding flow shall be re-

routed. Consequently, this instrument can only be applied on an interruptible basis, unless

the participating TSOs were willing to guarantee the firmness of the revised flow, for instance

by means of potential swaps between neighboring TSOs as explained in section 4.2.10.

To our knowledge, this option is already used by some European gas TSOs, in order to max-

imize the available transport capacity and to use the existing transport infrastructure in the

most efficient way. However, this clearly is not a wide-spread practice that was widely used

in the European gas markets. Similarly, there is little direct evidence from the European elec-

tricity market, not the least due to a much more limited control of load flows in a meshed

electricity grid. In some cases, however, European electricity TSOs coordinate for instance

the current switching state of their networks, or use so-called phase shifters, in order to in-

fluence load flows and make a maximum of capacity available to the market.

When neglecting the potential costs of compression, this mechanism could principally be

introduced based on an operational arrangement, but without any additional contractual or

other arrangements. In fact, the only condition that was really required would be effective

cooperation between all TSOs concerned. In order to avoid (structural) disadvantages for

certain TSOs and to provide incentives for mutual assistance, it might however be desirable

to agree on some form of compensation, in order to remunerate individual companies for a

less efficient use of their own network.


4.3 Objectives and Assessment Criteria

4.3.1 Overview

In order to evaluate the individual mechanisms described above, it is important to note that

they shall support a number of different, partially conflicting objectives. Table 7 therefore

summarizes a total of eight criteria which are subsequently used for a structured and com-

prehensive assessment of each mechanism in section 4.4 below.

To reflect the different nature and importance of individual criteria, we have divided them into

three different categories as follows:

Essential requirements, which must be fulfilled;

Primary objectives that are key to the underlying goals of market integration and the

establishment of a liquid and competitive gas market; and

Additional objectives, which should be fulfilled as far as possible but which are not

deemed to be critical, such that they may have to be traded off against the fulfillment

of other criteria.

Category Criterion

Essential requirements Ensure reliability of the gas system

Ensure compliance with EU and national legislation and regulation

Primary objectives

Promote economic efficiency

Ensure 'fair' distribution of risks

Ensure robustness against gaming

Additional objectives

Ease of implementation

Facilitate regional integration

Transparency

Table 7: Criteria for evaluation of potential mechanisms for congestion management


4.3.2 Essential Requirements

As it can already be seen from Table 7 above, we have identified two essential requirements

which are non-negotiable. For the integration mechanism to be acceptable, these criteria

must be fulfilled without any room for a trade-off of costs against benefits. In detail, we con-

sider the following two essential requirements:

Ensuring the reliability of the gas supply system; and

Ensuring the compliance with EU and national legislation and regulation.

The need to fulfill the first criterion is obvious. Any integration mechanism reducing the re-

liability of the gas supply system and thereby endangering the security of supply is not

acceptable. This basically means that the integration mechanism(s) applied must not result

in a situation where the TSO is no longer able to maintain the integrity of the gas network

and can hence no longer ensure a reliable supply of gas to consumers. To avoid any threat

to the reliability of the gas supply system, the TSO must thus have access to sufficient

means to ensure that the gas system can be operated within defined margins at all times.

This also requires that the integration mechanism (or rather the gas supply system after the

integration) possesses sufficient robustness to withstand the impacts of unforeseen incidents

or unforeseen behavior of shippers, infrastructure operators and consumers. This might for

instance be endangered if the integration mechanism relied on a purely voluntary participa-

tion of market parties without any means for the TSO to take immediate and rigorous ac-

tions, if so required.

The second essential requirement relates to compliance with the EU and the national

legislative and regulatory framework.23 This is of course self-explaining. The integration

mechanisms need to match the requirements stemming from French and European laws

and secondary legislation. Whereas the French legal framework could possibly be adapted

within limits to facilitate the market merger in general or the implementation of specific me-

chanisms, such changes should not alter the fundamental principles and the overall design

of the current market and regulatory arrangements. In contrast, we assume that the current

and expected legal and regulatory framework at the EU level has to be considered as a giv-

en that cannot be changed.

4.3.3 Primary Objectives

In addition to the two essential requirements mentioned before, we have also identified three

primary objectives for gas market area integration, which should be fulfilled to the maximum

23

Please note that the assessment provided in this paper cannot replace a sound assessment by legal experts.


extent possible. Primary objectives are those which are in the center of why the market area

integration is considered in the first place. This means that if the primary objectives are not

fulfilled, the basic purpose of the market area integration might be void. Whereas essential

requirements have to be met in any case, primary objectives may be achieved at different

degrees, i.e. to a higher or lesser extent. In principle, this means that when evaluating the

integration mechanisms, the fulfillment of the primary objectives has to be weighed against

the costs and benefits attached to each of the mechanisms.24

As illustrated by Table 7, the evaluation in section 4.4 considers three primary objectives:

Promoting economic efficiency;

Ensuring a 'fair' distribution of risks between market parties; and

Ensuring robustness against gaming by market parties.

The first primary objective is to promote economic efficiency. This means that the me-

chanism should provide incentives to all market parties to behave in a way which achieves

the most economic use of the available infrastructure and gas. The most basic incentive for

market parties to behave accordingly would be to generate economically efficient price sig-

nals. Additionally, the overall costs of the market area integration should be limited to a rea-

sonable level. This means that costs and benefits of the mechanisms should be in adequate

proportion to the benefits of market integration, in order to ensure an overall net benefit. Also

the distribution effects of each mechanism need to be considered. Finally, discrimination of

individual market parties or of a particular group of market parties should be prevented.

The second primary objective is to ensure a fair distribution of risks between different

market parties. This means that no party should be exposed to excessive risks, in particular

if the corresponding risks cannot be controlled and/or hedged by the corresponding party. In

other words, the opportunities and risks stemming from each mechanism should be ba-

lanced, and market parties should have a possibility to mitigate the risks they are exposed to

as far as possible.

The third primary objective finally is the robustness against gaming. This implies that the

overall objectives of the market area integration should not be easily compromised by stra-

tegic behavior of market parties. A mechanism should therefore not depend on the goodwill

of market participants, which should rather be regarded as rational and profit-maximizing

entities. Conversely, it should entail sufficient means, checks and balances to ensure that

the mechanism cannot be easily misused or that appropriate incentives are in place to avoid

24

In addition, the costs and benefits of each mechanisms principally also have to be weighed against the costs and benefits of marginal investments, which may facilitate market area integration.


undesirable behavior. Among others, this also includes the goal that a mechanism should

not enable market parties to generate unjustified profits.

4.3.4 Additional Objectives

Additional objectives mainly relate to the practical feasibility of each mechanism as well as to

broader objectives of gas market development. In contrast to the essential and key require-

ments and objectives identified in the previous two sections, they are deemed to be of less

importance such that deviations may be more acceptable in this case. Nevertheless, we

emphasize that the three items identified below still represent important objectives, which

should be carefully considered when evaluating different mechanisms.

In summary, we have identified three additional objectives, which should be fulfilled wherev-

er possible:

Ease of implementation;

Facilitation of regional integration; and

Transparency.

The first additional objective, ease of implementation, principally implies that it should be

possible to implement each mechanism with reasonable efforts. This means, for example,

that a fundamental revision of current market arrangements should be avoided or that the

need for additional contracts, trading platforms or IT systems should be in a reasonable pro-

portion to the expected benefits. Moreover, the complexity of each mechanism should be

manageable for market parties, including in particular for new entrants.

Secondly, facilitation of regional integration is also considered as an additional objective.

Gas markets all over Europe are subject to harmonization efforts, driven by EU legislation as

well as by joint efforts by the European regulators (ACER / ERGEG / CEER), TSOs

(ENTSO-G) and other market stakeholders. In this context, it is important that further integra-

tion of the gas market within France does not obstruct this process, especially with regards

to integration with neighboring countries, such as Belgium, Germany or Spain. Among oth-

ers, this implies that a mechanism should be compatible with solutions currently discussed

or applied in neighboring countries or at the EU level.

Thirdly, transparency is a key requirement to foster a competitive gas market. If markets

are opaque, it is hard for new entrants to determine the potential value of market opportuni-

ties, lessening their willingness to enter the market. Subsequently, any mechanism should

operate in a transparent manner, including the actions of the TSOs as well as those of other


market parties. Moreover, each mechanism should ideally contribute to the overall transpa-

rency of the market, but in any case not reduce it.

4.4 Qualitative Evaluation

4.4.1 Interventions outside 'Normal Operating Conditions'

As explained in section 4.2.2 this instrument allows the TSO to deal with congestion by di-

rectly interfering into the market and imposing restrictions or requirements on shippers to

adjust their nominations. This mechanism, which principally is already in place for situations

where network integrity is endangered, grants strong powers to the TSO in corresponding

cases. As illustrated in Table 8, interventions outside normal operating conditions therefore

provide a very powerful instrument to the TSO, in order to ensure the reliable operation of

the network.

In terms of legal and regulatory compliance, this mechanism clearly complies with the re-

quirements for each TSO to ensure the secure operation of the transmission system, as

already mentioned in Article 17(2)(e) of Directive 20095/73/EC. This generally positive as-

sessment is however based on the assumption that any corresponding interventions are

taken with a view to promoting third-party access to the network and that they carried out in

a non-discriminatory manner.

Perhaps the most important disadvantage of this mechanism relates to the fact that it is pri-

marily based on technical aspects but does not by itself consider the economic impacts. It

therefore seems reasonable to assume that any corresponding actions will likely be sub-

optimal from an economic perspective and may result in unnecessary costs to the system

and, ultimately, to consumers. Moreover, interventions by the TSO could result in serious

consequences for shippers and their customers, which will typically be very difficult to pre-

dict. Consequently, shippers will be exposed to potentially very serious risks, with no or only

limited and expensive possibilities to hedge against such risks. The benefits in terms of sys-

tem reliability thus come at the expense of a very uneven distribution of risks.

Moreover, small market players and new entrants may find it more difficult to hedge against

such consequences than large, incumbent companies with a well balanced portfolio and

sufficient access to flexibility. Although this mechanism can be considered robust against

gaming by market participants, it thus bears an inherent danger of discrimination towards

small and/or new market participants.


Overall, it therefore seems clear that interventions outside 'normal operating conditions' can-

not be regarded as an option of choice to deal with physical congestion after the market

merger. This does not come as a surprise, since this possibility is principally meant to deal

with emergencies and should hence only be employed when network integrity or crucial

supplies are endangered. In such cases, the problems mentioned above may be considered

as secondary or at least acceptable in comparison with the alternative of potentially severe

interruptions of supply.

In summary, this instrument clearly is not suited for dealing with regular congestion patterns

or other types of congestion which do not have a major impact on the network. Nevertheless,

it can also be useful for rare cases of congestion where other more light-handed and market-

based instruments may fail to avoid/resolve congestion. In these cases, corresponding inter-

ventions could provide a tailored back-up solution of last resort, although their regular use

should be avoided. The flow patterns and the sequence of conditions triggering such a me-

chanism (e.g. the failure of other market-based mechanisms) could be made publically

available in order to increase transparency.

Evaluation Criteria / Performance Comments

A) Guarantees reliability + Fully controlled by the TSO

B) Legal / regulatory compliance +/- Non-discrimination needs to be controlled

C) Economic efficiency - Dispatch is based on technical and not on

economic considerations

D) ‚Fair‘ distribution of risks - All risks on side of shippers,

no means of hedging

E) Robustness against gaming + Fully controlled by the TSO

F) Ease of integration + Already in place

G) Facilitates regional integration +/- Compliant, regular use may give cause to

discussions, though

H) Transparency +/- Lack of transparency, clarification of rules

would be required

Table 8: Evaluation of interventions outside normal operating conditions

4.4.2 Interruptible Capacities

Similar to the case of interventions outside normal operating conditions, the use of this in-

strument provides the TSO with significant control of network flows, which can be used to

ensure the reliable operation of the network. Moreover, interruptible capacities are explicitly


mentioned in Regulation (EC) No 1775/2005 and the Pilot Framework Guideline on Capacity

Allocation Mechanisms25. As such, this instrument can therefore be considered as being fully

compatible with the relevant legal and regulatory requirements.

Similar to the previous case, the main drawbacks of this mechanism are related to economic

efficiency and the distribution of risks between the TSO on the one side, and shippers on the

other side. Given the lack of any market-based signals, the use of either interruptible or con-

ditional capacities is unlikely to result in an economically efficient outcome. Among others,

both types of restrictions would equally apply to all holders of such capacity, irrespective of

whether the corresponding shippers plan to utilize their capacity rights or not. As a conse-

quence, there is a substantial risk that an overly large amount of capacity may have to be

withheld from the market, in order to keep network flows within acceptable limits. Similarly,

the need for transparent criteria may undermine the effectiveness of this approach, as it may

be more difficult to precisely target the actual needs of the network on a given day. Similar to

the case of interventions outside normal operating conditions, interruptible as well as condi-

tional capacities finally create an uneven balance of risks. Notably, shippers will generally

find it difficult to hedge against the underlying risks, at least in terms of price risks.

These aspects would be less critical in case of short-term capacities, although a deficit of

long-term capacities may act as a barrier to entry and result in a sub-optimal use of capacity.

Nevertheless, especially when used in combination with a market-based allocation proce-

dure (i.e. auctions) the use of short-term capacities avoids many of the issues related to

interruptible or conditional capacities.

Another aspect worth mentioning is implementation. If un-booked capacities are used, no

issues are to be expected. Conversely, and as already mentioned in section 4.2.3, the con-

version of existing firm capacity rights would principally require the consent of current ca-

pacity holders. Our discussions with shippers have however shown that the conversion of

already contracted firm capacity to a less firm (and less valuable) capacity product is a sen-

sitive issue for many shippers. Consequently, it seems reasonable to expect that the applica-

tion of this instrument for existing capacity right would face substantial opposition from hold-

ers of incumbent capacity rights.

Another issue in this context relates to the criteria to be used for the interruption or use of

interruptible and conditional capacities, respectively. Although this may seem easy in prin-

ciple, the development of criteria which combine sufficient flexibility to best meet the sys-

tem's requirements with the objective of transparency, can be expected to be intrinsically

difficult.

25

ERGEG. Revised Pilot Framework Guideline on Capacity Allocation Mechanisms. E10-GWG-71-03. 7 Decem-ber 2010


Overall, interruptible or conditional short-term capacities do therefore not appear to be a

preferred choice, in particular in case of regular but limited congestion patterns. However,

they may provide a useful instrument for dealing with structural congestion, in particular if a

share of capacity has not yet been allocated to shippers. Conversely, the use of short-term

capacity rights seems to be much better suited, especially when used in combination with a

market-based allocation procedure. Nevertheless, even in this case, the practical application

of this instrument may be largely limited to capacity which has not yet been allocated to the

market and can thus easily be converted to short-term capacity. Moreover, the application of

this option may be limited by the provisions of the draft Network Code on Capacity Allocation

Mechanisms, which does not foresee any reservation of capacity for periods shorter than a

quarter of a year or a month.

With regards to the assessment in Table 9, we emphasize that this is principally valid for the

case of unsold capacities only. In contrast, implementation would obviously be difficult if one

intended to convert booked capacities, such that the latter option would clearly have to be

negatively qualified in terms of criterion "F" (ease of integration).

Evaluation Criteria / Performance Explanation


B) Legal / regulatory compliance + Provided that transparent criteria are used

C) Economic efficiency +/-

Uncertainty may lead to potentially sub-optimal use of capacity; advantages for incumbents, economic signals on whom to interrupt required Less critical in case of short-term capacities

D) ‚Fair‘ distribution of risks - All risks on side of shippers, limited possibilities of hedging


F) Ease of integration (+) Easy in principle – but how to define the criteria for interruption / use?

G) Facilitates regional integration +/- Fully compliant, but reduction of firm capacity may reduce benefits of integration

H) Transparency (+) Depending on criteria used for interruption / con-ditionality

Table 9: Evaluation of interruptible capacities (unbooked capacity)

4.4.3 Locational Restrictions

Imposing locational restrictions would improve the predictability of load flows and thus de-

crease the complexity of an enlarged market area in a decoupled entry-exit system. As such


a mechanism would be fully controlled by the TSO, it could well facilitate reliability and feasi-

bility of network flows.

However, the shipper's freedom to access every exit point from any entry point is the basic

characteristic of the entry-exit network access model as stipulated by Regulation EC No

715/2009. Limiting the allocable freedom of capacities within the entry-exit regime could

factually lead to a reintroduction of point-to-point contracts and would contradict the general

development of network access models in the European Union over the last years. It cannot

be judged without an in-depth assessment if such an approach would be possible within the

European or the French legislative framework However, similar mechanisms are applied at

present for instance in Belgium and Germany. It seems reasonable to assume that any po-

tential legal conflicts could be minimized by applying such locational restrictions only on ca-

pacities additionally made available to the market.

Such capacity products are more attractive for certain shippers, i.e. shippers transiting gas

or supplying industrial consumers with a flat base load curve. For the majority of shippers it

may be a problem that hedging against being restricted to the stipulated entry-exit link is only

very limitedly possible and thus capacities would be barely more valuable than normal inter-

ruptible capacities. The nature of the restrictions may also favor incumbent market parties

and distort market prices, as flows subject to locational restrictions would be barred access

to the virtual trading point. Additionally, the problem that already contracted capacities would

need to be converted is similar as described with regards to using interruptible or conditional

capacities.

If a capacity product using locational restrictions was accepted by the market and also im-

plemented in a transparent and non-discriminatory way, and if non-compliance with Euro-

pean and national legislation could be avoided, the mechanism would be suited to avoid and

to resolve limited but regularly occurring congestion patterns.




B) Legal / regulatory compliance - Contradiction to spirit of E/E tariffs but may possibly constructed with inter-ruptible capacities

C) Economic efficiency +/-

Can be tailored to individual cases but may discriminate in favor of certain shippers Limits impact of market price signals on flows

D) ‚Fair‘ distribution of risks - All risks on side of shippers, limited possibilities of hedging


F) Ease of integration +/- Easy in principle – but how to define criteria for interruption / use?

G) Facilitates regional integration - Deviation from principle of E/E system; may reduce capacities for regional integration

H) Transparency +/- Can be transparent, but concerns with regards to potential disclosure of indi-vidual shipper‘s constraints

Table 10: Evaluation of locational restrictions

4.4.4 Capacity Buy-Back

The results of a capacity buy-back mechanism would be similar to using interruptions, i.e.

capacity available for transport is reduced on a case-by-case basis in order to achieve over-

all feasible network flows. The main difference would be, though, that the TSO would be

required to ask for the required capacities on a regular basis, up to daily, if the capacities

cannot be acquired by acting as counterpart for sales offers on the secondary market, an at

present highly illiquid market. The mechanism would thus bear the inherent danger that the

TSO could end up in the position of a distressed buyer, opening the potential of market play-

ers exploiting the system by strategic behavior. Moreover, in cases of severe congestion, no

shipper may be willing to give back capacities voluntarily. Thence, doubts regarding the fea-

sibility of a voluntary buy-back mechanism seem to be justified, although from the theoretical

perspective it seems to be a very efficient approach, as capacities would be taken from

those shippers who put the least value to their capacities.


In order to overcome the problem of the TSO ending up as distressed buyer, the mechanism

could be designed less voluntary, forcing shippers to offer capacities in a buy-back scheme.

In that case the system would very much resemble the usage of last-resort actions under

normal operation conditions and the usage of interruptible capacities, although with a reim-

bursement set by the shipper but valid for all shippers. Subsequently, the arguments de-

scribed above are also valid for a mandatory buy-back scheme.

The buy-back scheme could thus be used twofold, either on a voluntary basis for regular but

limited congestion patterns, and with other mechanisms in place in case the buy-back does

not provide the desired results, or as a mandatory scheme in order to provide a more trans-

parent and economically efficient approach to how actions of last-resort are deployed by the

TSO.


A) Guarantees reliability (-) TSO could end as distressed buyer. How to ensure sufficient offers de-pends on heavy-handedness?

B) Legal / regulatory compliance + No issues foreseen

C) Economic efficiency + Market-based approach principally promotes economic efficiency

D) ‚Fair‘ distribution of risks +/- Full certainty for shippers but no hedge for TSO; costs socialized via TSO

E) Robustness against gaming - If TSO in position of distressed buyer, high potential for strategic behavior

F) Ease of integration - Requires separate mechanism for ca-pacity buy-back, secondary market not liquid enough.

G) Facilitates regional integration + No issues foreseen

H) Transparency (+) Principally fully transparent – although concerns remain in case of limited market potential

Table 11: Evaluation of capacity buy-back

4.4.5 Locational Trades

Locational gas trades could resolve congestion by relieving flows or triggering counter flows.

In order to successfully mitigate the problem, the TSO would be relying on acquiring or sell-


ing gas at exactly specified entry or exit points. Hence, in order to deploy the mechanism, a

market place for locational trades would be required.

This basic nature of the mechanism poses the biggest problem, as there is a high level of

uncertainty as to whether the TSO would be able to successfully acquire the necessary vo-

lumes. In a most unlikely scenario, i.e. when no back-up instruments are available, the TSO

could even risk ending up as distressed buyer, the same as with capacity buy-back. The risk

is thus fully borne by the TSO.

If the required commodity trades can be facilitated, the instrument seems to be well suited to

resolve congestion directly at the source of origin. The instrument seems to be in line with

legal requirements and basically is non-discriminatory. However the nature of the instrument

may favor larger market parties with diversified portfolios. In specific situations, the mechan-

ism may enable larger market parties to game the market for locational products, as this

market will supposedly be very small. This risk would however be mitigated by the fact that

other instruments would be required as well, as is argued below.

Given the market-based approach of locational trades, they seem to be well suited to resolve

limited but frequent cases of congestion in a transparent and economically efficient way.

However, due to the uncertainty of the instrument, it should only be part of a larger portfolio

of possible instruments in order to resolve congestion.



A) Guarantees reliability - Uncertainty about successful procure-ment in case of need

B) Legal / regulatory compliance + Fully compliant

C) Economic efficiency + Market-based approach promoting efficiency, potentially favors large players with diverse portfolio

D) ‚Fair‘ distribution of risks +/- Single risk for TSO that mechanism is not sufficient to resolve congestion

E) Robustness against gaming +/- Large player may have potential to game market for locational product

F) Ease of integration +/-

Commonly known approach in balanc-ing market, no issues foreseen, how-ever separate balancing product or separate market required


H) Transparency + No issues foreseen

Table 12: Evaluation of locational trades

4.4.6 Flow Commitments

Flow commitments are an instrument in effect very similar to the locational trades above.

With load flow commitments, the TSO would contract with market parties to ensure a speci-

fied injection or withdrawal flow at a network point or a flow between two points on demand.

In comparison with locational trades though, the TSO would have the flow it would like to

trigger with the locational trades firmly contracted for a longer time period. Thus, the certain-

ty for the TSO is provided once the required flow commitments have been made.

One of the main problems of flow commitments is that similar to locational trades there is

potential for discrimination, as often only the larger incumbents are able to provide flow

commitments (also depends on time period and lot size). Flow commitments are a proven

instrument in Germany where they have been used for balancing and in order to merge mar-

ket areas. However, they are disputed because of their complexity and costs. Additionally,

the deployment of flow commitments in the German gas networks suffers from opacity; in-

formation is not transparent.


In combination with locational trades this instrument may make even more sense. If loca-

tional trades are used to mitigate congestion, some market parties could be contracted to

provide the necessary trades in case of need on a capacity basis (i.e. appointing market

makers), whereas the market in general would also be open for all other market players,

thus avoiding that some market parties are favored by the mechanism.

Summing up, flow commitments seem to be well suited to handle regular limited but also

more severe cases of congestion, provided that they are procured in a transparent and non-

discriminatory manner.


A) Guarantees reliability +/- Certainty after completing tender


C) Economic efficiency TBD Depends on liquidity of market, need to consider option value of con-tracts

D) ‚Fair‘ distribution of risks (+) If commitments are offered voluntarily, no real risk for shippers, TSO bears risk whether instrument is sufficient

E) Robustness against gaming +/- Large players may have potential to game market place, could be mitigated easily

F) Ease of integration +/- Requires separate market place, or special product in balancing / wholesale market


H) Transparency +/- Issue in Germany, needs to be careful-ly implemented in order to ensure transparency

Table 13: Evaluation of flow commitments

4.4.7 TSO-Contracted Storage

Having storage capacity available to the TSO in order to balance the network above and

below the constraint would be a high-powered and very reliable mechanism, dependent on


having sufficient capacity to bridge the time period during which the congestion prevails.

Thus, the mechanism is obviously only suited to resolve regular congestion which occurs

only for short intervals and for non-structural congestion, giving the TSO the chance to "rel-

oad". At the same time, using storage contracted by the TSO in order to resolve congestion

happening only a few hours per year would be very expensive.

The usage of storage would be in line with legal requirements. If storage capacity would be

contracted firmly from affiliated companies who may have concerns regarding non-

discrimination, the mechanism would bear the inherent danger of cross-subsidization, or

would at least be ridden with suspicions in this regard.

Additionally, the storage, once contracted, could crowd-out more efficient flexibility offers

made by shippers and other potential parties, at least during the time until the TSO re-

considers using storage as a flexibility tool, i.e. at least the storage contract duration.

Using storage would take away the immediate risk from shippers and also the risk for the

TSO would be limited, provided that sufficient storage capacity is contracted. The risk would

be borne instead by shippers and their customers as it would obviously result in higher net-

work charges. The mechanism seems invulnerable against strategic behavior of shippers

and to deploy it in a transparent manner could easily be possible.

All things considered, contracting storage through the TSO in order to resolve congestion

seems to be a well suited mechanism for very frequent (up to daily) but limited congestion,

i.e. factually as an extension of linepack. It could also serve as fallback mechanism for other

light-handed interventions, although if used too seldom it would probably be too expensive.



A) Guarantees reliability +/- Depends on storage capacity and vo-lume

B) Legal / regulatory compliance (+) Potential competition with market but similar products used in other coun-tries as well

C) Economic efficiency - De-couples storage use from market, potentially very expensive, crowding-out effect

D) ‚Fair‘ distribution of risks (+) Hedge for TSO without any direct risks for shippers (but reduction of flexibility and higher network charges)

E) Robustness against gaming + Fully controlled by TSO

F) Ease of integration + Direct contract TSO - storage provider


H) Transparency + No impact on wholesale market

Table 14: Evaluation of TSO-contracted storage

4.4.8 Locational Storage Swaps

Locational swaps would in essence work similarly to storage directly contracted by the TSO.

In the case of locational swaps, the gas volumes required to balance network parts above

and below the constraint would not be provided by the TSO by using own storage capacities.

Instead a service would be contracted from storage and/or LNG terminal operators.

In general the mechanism is assessed in a similar way to TSO-contracted storage and all

arguments described above prevail.

However, together with the option of integrating flexibility provided by LNG terminal opera-

tors and adding the possibility of re-routing LNG cargoes from one terminal (above the con-

straint) to another terminal (below the constraint), this would result in an even higher-

powered tool. Re-routing of LNG cargoes could eventually recharge storage capacities re-

quired for day-to-day operations. Thus, provided that storage capacities are sufficient to

bridge congestion for the time required to re-route an LNG vessel, and assuming enough

flexibility on the side of LNG terminal operations, even structural congestion could be re-

solved. Effectively, LNG transports bypassing the constraint would replace pipeline invest-

ments.



A) Guarantees reliability +/- Depending on amount of flexibility con-

tracted


C) Economic efficiency TBD No influence on wholesale market (may be different for LNG option)

D) ‚Fair‘ distribution of risks (+) Hedge for TSO without any direct risks

for shippers

E) Robustness against gaming + No interaction with market (storage)

- LNG option depends on market

F) Ease of integration

+ Direct contract TSO - storage provider

+/- LNP option requires multi-party

agreement and longer lead-times


H) Transparency

+ No impact on wholesale market

+/- Potential concerns regarding LNG

deals

Table 15: Evaluation of locational swaps

4.4.9 Swaps between Neighboring TSOs

Swaps between neighboring TSOs would rely on mutual support. TSOs would be lending

each other their flexibility. The agreements could be made on a best endeavor basis, avoid-

ing serious costs for the TSOs, i.e. it would make little sense for a TSO to procure additional

flexibility to be able to help its neighbor. The mechanism would be fully in line with the legal

and regulatory framework. The mechanism would improve regional integration as it would

increase cooperation of TSOs, although cross-border cooperation already takes place to a

certain amount.

However, on a best endeavor basis, the availability of the neighbor's help would rely on

whether the neighbor has flexibility to spare. Moreover, spare flexibility of a neighboring TSO

could be needed by the neighbor itself due to changes of flows because of intra-day re-

nominations or unforeseen incidents. Thus, the instrument is not very reliable. Additionally,

as the mechanism sets to work only at the cross-border points, it is probably not very well-

aimed to resolve congestion deep within the network.


The mechanism may thus be suitable as one instrument in a larger toolbox to solve conges-

tion, not replacing the need for more reliable backup-mechanisms.


A) Guarantees reliability - Flexibility cannot be guaranteed


C) Economic efficiency + TSOs “lend“ each other flexibility free of charge and use the whole system

efficiently

D) ‚Fair‘ distribution of risks + No issues foreseen

E) Robustness against gaming + Assuming that no neighboring TSO

has a hidden agenda

F) Ease of integration + Direct agreement between TSOs, does

not affect shippers

G) Facilitates regional integration + Promotes regional integration

H) Transparency (+) Depends on reporting about usage

Table 16: Evaluation of swaps between neighboring TSOs

4.4.10 Re-Routing of Gas Flows

Same as swaps between TSOs, re-routing flows through neighboring networks would be

based on mutual support, on a best-endeavor basis. Instead of coordinating only two neigh-

bors it would include coordination among three or more TSOs. In essence, the same analy-

sis as provided above with regards to swaps between TSO is relevant. Additionally, the

coordination of more than two parties is necessarily more complex, which burdens this me-

chanism with a high administrative effort.



A) Guarantees reliability - Flexibility cannot be guaranteed


C) Economic efficiency + TSOs optimize use the whole system,

as within enlarged E/E model

D) ‚Fair‘ distribution of risks + No issues foreseen

E) Robustness against gaming + Assuming that no neighboring TSO

has a hidden agenda

F) Ease of integration + Direct agreement between TSOs, does

not affect shippers

G) Facilitates regional integration + Promotes regional integration

H) Transparency (+) Depends on reporting about usage

Table 17: Evaluation of re-routing gas flows through neighboring networks

4.5 Summary of Findings and Initial Conclusions

The discussion of the individual mechanisms in the previous section 4.4 has shown that

none of the individual mechanisms is clearly superior with regards to the whole set of eval-

uation criteria defined in section 4.3. As a general rule, market-based mechanisms, including

in particular locational trades, can be considered as a preferred solution from the perspective

of economic efficiency and the underlying objective of developing a liquid and competitive

gas market. However, with the potential exception of flow commitments, market-based me-

chanisms are not generally able to ensure a guaranteed reliability of the network. This im-

plies that it may be necessary to consider the application of other, administrated solutions, at

least where it is absolutely necessary to ensure the physical integrity of the network.

These considerations mean that it will likely be necessary to rely on a combination of differ-

ent mechanisms in practice, which can be best tailored to different types of physical conges-

tion. In other words, the properties of different congestion scenarios may be used to define

specific requirements and to identify a suitable choice of mechanism(s) for each type of con-

gestion. The rationale behind this approach is the assumption that different situations, i.e.

different types of congestion, require the use of a different (set of) mechanism(s), depending

on impact and frequency of congestion.

This concept is illustrated in Figure 20, which schematically depicts the relation between the

frequency and impact of physical congestion and the resulting requirements for congestion


management mechanisms. Based on this figure, one may identify the following fundamental

requirements on suitable mechanisms for congestion management as follows:

For the central part of Figure 20, which is characterized by regular but limited physi-

cal congestion, the primary focus should be on economic efficiency. The means that

a suitable mechanism should be aimed at resolved congestion at the lowest possible

costs, whilst also minimizing potential distortions of the overall gas market. Con-

versely, it may be possible to accept a higher risk of the TSO being unable to imme-

diately resolve physical congestion, provided that the TSO has access to some back-

up solution in order to deal with corresponding problems.

Similarly, in case of structural congestion with a limited impact (see bottom right of

Figure 20), the focus should be on costs and market impact. Given the structural na-

ture of congestion, it would however be necessary to ensure that the TSO can safely

manage any corresponding problems, even at the expense of higher costs.

Conversely, in case of infrequent but serious congestion (see top left in Figure 20),

attention should be primarily paid to the need for ensuring the reliable operation of

the system. Conversely, the costs of the mechanism as well as potential distortions

of the overall market may appear to be more acceptable in this case.

Finally, it appears questionable whether it would be possible to deal with the case of

both structural and serious congestion without any additional investments, as indi-

cated by the top right corner of Figure 20.

Figure 20: Requirements on congestion management mechanisms in relation to the

impact and frequency of congestion

Frequency

Imp

ac

t

High

High

Low

Low

Minimize market interference

May accept larger risk for TSO (+ back-up?)

Limit transaction costsMinimize market

interference and transaction costs

Market integration

feasible?

Need for reliability

Market interference may be acceptable


Based on these considerations, and taking into account the findings of the qualitative evalua-

tion in section 4.4, we believe that market-based mechanisms should be regarded as the

preferred choice at least for congestion with a low to medium impact. This conclusion results

mainly from their advantages with regards to economic efficiency and their compatibility with

the overall gas market.

As indicated by the lower part of Figure 21 below, we specifically propose the following for

the case of congestion which has a low to intermediate impact:

Wherever possible, some form of locational trades, which should be procured on a

daily basis, should be regarded as the preferred choice.

Secondly, capacity buy-back mechanisms may be applied as an alternative to loca-

tional trades, especially in case of infrequent congestion26 or where excess flows

have to be reduced.

Thirdly, flow commitments may have to be considered as an alternative, namely in

case of insufficient competition or where longer lead times are requires. In the first

case, the use of flow commitments may help to minimize the risk of unexpectedly

high prices and/or to mitigate the potential impact of market power. Consequently,

flow commitments may be required in case of structural congestion, which will often

coincide with a limited scope for competition. In addition, flow commitments may also

represent the only market-based solution in situations where it is necessary to take

decisions well in advance of actual delivery (e.g. several weeks or even months), in

order to ensure the availability of sufficient volumes of commodity.

Finally, where capacity has not yet been allocated to the market, the conversion of

firm to interruptible capacity may provide another instrument for managing struc-

tural congestion that occurs with a high frequency.

26

I.e. where it may not be economic or practical to rely on locational trades


Figure 21: Schematic clustering of different congestion management mechanisms to

different types of physical congestion.

(a) - In case of insufficient competition and/or long lead times

Despite the general merits of market-based mechanisms, these may be unable to ensure

reliability in case of extreme congestion, or only at excessive costs. We therefore also rec-

ommend considering the application of other, administrated mechanisms, which are shown

in the upper part of Figure 21:

To deal with serious physical congestion, which occurs on a rare to regular basis, it

may be necessary to additionally rely on either interruptible / conditional capaci-

ties or the use of short-term capacities. The use of this method would allow the

TSO to safely manage the network, whilst avoiding excessive costs to shippers

and/or consumers.

Nevertheless, it does not appear useful to cover for even the most extreme cases of

physical congestion, provided that these occur very seldom. Instead of potentially

having to convert a large proportion of available capacity to an interruptible product, it

appears more beneficial to treat such situations as being outside normal operating

conditions, i.e. by means of direct interventions by the TSO. Given that it is imposs-

ible to exclude the possibility of corresponding events, this mechanism may in any

case be required as an instrument of the last resort, in order to ensure the physical

integrity of the system in very rare situations.

With regards to the choice between interruptible / conditional capacity on the one hand, and

short-term capacities on the other hand, we believe that this decision should among others

Frequency

Imp

ac

t

Permanent

High

Low

Seldom

Locational Trades /

Capacity buy-back(Flow commitments (a))

Invest

TSO

storage

Flo

w

co

mm

itmen

ts/

Inte

r. cap

acity

Interruptible capacity

Operating Conditions


be driven by the frequency and predictability of congestion. For instance, if congestion oc-

curs very seldom or can be well predicted in advance, interruptible capacities may provide

for a suitable instrument, as the corresponding risks either remain minimal or can be as-

sessed with reasonable accuracy. Conversely, short-term capacities may be better suited for

more frequent but unpredictable congestion, which involves a much higher degree of uncer-

tainty. However, any corresponding mechanism would obviously have to comply with the

provision of the Network Code for capacity allocation mechanisms, which may limit the prac-

tical use of this instrument.

The bottom part of Figure 21 also includes the option of TSO-contracted storage. As already

mentioned in section 4.4.7, we believe that this instrument – whilst being potentially useful –

will usually be limited to cases of limited congestion, which is not of a structural nature. Its

application should be strictly limited, however, to cases where it does not compete for scarce

storage capacity and where it can be expected to result in reduced costs.

Finally, we note that it may also be beneficial to consider the use of the other mechanisms

involving other infrastructure operators, such as locational storage or TSO-to-TSO swaps, or

the re-routing of flows. As already mentioned in sections 4.4.8 to 4.4.10, however, we be-

lieve that especially the two latter options may be helpful but cannot be relied upon. As such,

we regard these mechanisms mainly as supplementary instruments that may help to optim-

ize the use of the 'standard' solutions identified above. Consequently, these measures may

principally complement all of the instruments shown in Figure 21.


5. Evaluation of Options for Congestion

Management after the Market Merger

5.1 Introduction

The analysis in chapter 3 has shown that the merger of the GRTgaz market zones may lead

to a significant risk of physical congestion in some cases. Unless it was decided to under-

take additional and potentially substantial investments in grid extensions, congestion would

need to be managed by appropriate congestion management procedures. Chapter 4 has

identified and qualitatively assessed a number of potential mechanisms which could be used

in this respect. This included an evaluation of the advantages and drawbacks of each me-

chanism and led to some preliminary recommendations of suitable instruments for dealing

with different types of congestion.

Based on this background, the purpose of this chapter 5 is to condense the findings of the

previous analysis, in order to identify appropriate means for managing potential congestion

in the French transmission network. This analysis is structured along the three main conges-

tion patterns identified in chapter 3.2, which are discussed in the following sections 5.2 to

5.5. For each type of congestion, we first discuss the physical means of resolving conges-

tion, before considering which mechanisms to use in which case. The outcome of this dis-

cussion is then used to assess the potential costs of congestion management in section 5.6.

The last part of this chapter (section 5.7) finally summarizes our corresponding findings and

presents the recommended options which are further detailed in the following chapter.

5.2 Physical Options for Mitigating Congestion in North-

South Direction

5.2.1 Introduction

The analysis in chapter 3 has revealed a substantial risk of serious congestion in the North-

South direction. More specifically, we have found that structural congestion in the summer

months may reach levels of up to 300 GWh/d to 500 GWh/d in scenario 1. Various sensitivity

runs have confirmed the robustness of this finding. Nevertheless, our analysis has also


shown that the level of congestion is sensitive to several assumptions, for instance with re-

gards to the seasonal spread of spot prices or price levels on the Spanish market in compar-

ison to North-Western Europe.

In the discussions with the Concertation Gaz, it was particularly pointed out that the as-

sumed seasonal spread of 5 €/MWh for North-West European spot prices appeared as a

relatively strong assumption in view of the experience from recent years. In order to avoid

basing the following analysis on an overly pessimistic set of assumptions, we have simulated

an additional 'non-conservative' scenario. This scenario is based on scenario 1 with full take-

or-pay obligations, but subject to the following modifications:

Reduced seasonal spread of spot prices in North-Western Europe (3 €/MWh);

Reduced spread between the price of LNG imports and the price of long-term con-

tracts for pipe imports (3 €/MWh); and

Limitation of net annual exports to Spain to 28 TWh27.

As illustrated by Figure 22 these assumptions reduce congestion in the summer months by

approx. 50 GWh/d. Yet conditions 1a and 2a are still violated by up to 300 GWh/d in the

summer, whilst there is limited and irregular congestion in the winter only. In contrast, the

violation of condition 4 decreases to relatively small volumes even during the summer. In the

remainder of this section, we therefore focus on congestion defined by conditions 1a and

conditions 2a, which appear to be the most critical.

27

Based on experience from recent years


Figure 22: Reduction of physical congestion in North-South direction in the 'non-

conservative case' in scenario 1

Note: Figures show daily violation of congestion inequations (in GWh/d)

As already mentioned in section 3.4 it appears that the exchange with Spain is one of the

most critical drivers for congestion in the North-South direction. Similarly, and not surprising-

ly, congestion seems to be strongly influenced by Fos, i.e. notably by limited deliveries of

LNG gas to the South of France. This view is also confirmed by the fact that conditions 1a

and 2a are both primarily related to the flows at these two entry/exit points.

0

100

200

300

400


Co

nge

stio

n (G

Wh

/d)


Base Case Non-conservative case

0

100

200

300

400


Co

nge

stio

n (G

Wh

/d)

Cond 2a (Min FOS - TIGF (if positive))


0

100

200

300

400


Co

nge

stio

n (G

Wh

/d)




Indeed, as specified above, these two conditions are defined as follows:

Condition 1a: Min Entry Montoir + Entry Fos – Exit TIGF

Condition 2a: Min Entry Fos – Exit TIGF | if exit to TIGF is positive

The mathematical formulation of both constraints clearly illustrates the importance of the two

entry/exit points. On first sight, it might thus appear that congestion in the North-South direc-

tion can only be resolved by increasing the entry flow at Fos and/or by reducing potential

exports to TIGF. But as also illustrated by the alternative mathematical formulations of condi-

tions 1 and 2 provided by GRTgaz28, congestion is always a function of the net exit flows

downstream and the net entry flows upstream of the constraint. Similarly, we have already

pointed out that the conditions developed by GRTgaz are based on a set of assumptions on

the use of storages and CCGT29 plants. However, in practice a different use of both storages

and CCGTs may potentially help to relieve congestion. In the following section, we therefore

first investigate the potential impact of these sources. Thereafter, we specifically focus on

possible measures at Fos and the border to TIGF.

5.2.2 Potential Impact of CCGT plants

The congestion conditions defined by GRTgaz are based on specific assumptions on the

use of CCGT plants. More specifically, for the critical conditions 1a and 2a, it is assumed

that all CCGTs downstream of the corresponding constraint are operating at 100% of their

capacity, at least for some hours during the day. In reality, this may not always be the case,

in particular when taking into account the increasing impact of solar power on the regional

electricity market30, with the effect of decreasing prices during peak hours. Consequently, it

appears that the actual level of congestion may be over-estimated, even when accounting

for potential variations in hourly electricity production (and hence gas consumption) over the

day.

28

In accordance with the information provided in Annex 1, condition 1 can also be expressed as: Max Entry Taisnières + entry Obergailbach – exit Oltingue + entry Dunkerque. Similarly, condition 2 can alternatively be written as: Max Entry Taisnières + entry Obergailbach – exit Oltingue + entry Dunkerque + entry Montoir

29 Combined cycle gas turbines

30 The French electricity market is well integrated with the neighboring markets in Belgium, Germany, Switzer-

land. It is thus also influenced by the rapid growth of solar power in Germany, which is expected to reach some 17 GW by the end of 2011 and grow to more than 50 GW by 2020. This development has already caused a marked reduction in hourly electricity prices during peak hours; an effect, which is widely expected to increase in the future. Given that CCGTs generally provide peak load (in particular in France with its huge nuclear fleet), it thus seems reasonable to expect that this development will also have a strong influence on the operation of French CCGTs, including those in the south of the country.


To assess the potential uncertainty we have considered the CCGT operating pattern, which

we have used in our simulations; see Figure 23. Actual output never reaches 100% of the

potential capability and stays below 75% of the theoretical potential for almost the entire

time. Similarly, the average load factor during the period amounts to 41%, indicating that

actual consumption is substantially less than 50% of potential off-take on average.

As mentioned the pattern in Figure 23 is based on actual output in 2010, whilst production

may vary significantly from year to year. Moreover, the output of CCGTs may not be known

in advance but may be subject to significant changes, for instance due to the additional sales

or purchases in the intra-day and/or balancing markets. To assess the potential congestion

relief, we therefore make the assumption that the actual output of CCGT plants during the

summer season safely remains below two thirds of the maximum off-take on average. Con-

versely, the level of congestion can then be estimated to be relieved by approx. 1/3 of the

aggregate off take capacity of all CCGTs that are relevant for this constraint.

Figure 23: Daily output of CCGT plants between mid April and mid October

In Table 18, we have applied the corresponding assumptions on the maximum daily capacity

of all CCGTs that are contributing to each congestion. We see that, under these assump-

tions, congestion decreases by 55 and 42 GWh/d for conditions 1a and 2a, respectively. We

emphasize that these numbers represent average values, which have to be interpreted with

considerable caution. First, actual values on individual days may vary considerably, as indi-

cated by the fluctuating output shown in Figure 23. Moreover, Table 18 effectively assumes

a flat daily off-take, whilst ignoring hourly fluctuations during the day. Depending on the level

of diurnal flexibility available to the southern part of the network locally, the relief of conges-

tion may be significantly lower than shown in Table 18, potentially down to zero.

0%

25%

50%

75%

100%

Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15

Ou

tpu

t in

% o

f in

stal

led

cap

acit

y


Condition Aggregate daily off-take by

CCGT plants (GWh/d) (a)

Reduction of congestion (b)

(GWh/d)

Condition 1a 165 55

Condition 2a 126 42

Table 18: Potential reduction of N-S congestion due to actual CCGT operating pattern

(a) – See Annex 1, p. 27; condition 2a including the daily capacity of Saint-Vulbas (b) – Assuming an effective load factor of 66%

Finally, the second column of Table 18 also indicates that CCGTs represent a potentially

rather effective instrument for reducing physical congestion in the North-South direction. For

example, when all corresponding CCGTs were switched off, the constraints on condition 1a

and 2a would be relieved by 165 and 126 GWh/d, respectively. These numbers show that

electricity producers could potentially provide more than 100 GWh/d of congestion relief to

the network at all times of the year, which represents a significant lever in this respect.

5.2.3 Potential impact of underground storage

Similar to the case of CCGTs, the congestion conditions are based on fixed assumptions on

the operation of underground storages. More specifically, the conditions for congestion from

North to South have been determined for a situation where all storages inject at 100% of the

so-called climatic capacity during the summer.31 Conversely, lower levels of injection into

certain storages help to relieve some of the congestion conditions, notably including condi-

tions 1a and 2a. In this context, it is furthermore worth noting that injections during the sum-

mer may indeed be significantly lower than climatic capacities (see Figure 24 below). Con-

sequently, it appears that the actual level of congestion may be less than indicated in our

original results (see section 3.4 and Figure 22 on p. 76 above).

31

As already mentioned, this use of storages, which represents the most robust use from a network perspective, was taken in order to give shippers full flexibility on the use storages.


Figure 24: Comparison between climatic capacity (red) and simulated operation (blue)

of underground storages in the GRTgaz area

As mentioned, lower levels of injection may help to reduce North-South congestion in the

summer. Although the principle is the same, the corresponding impact differs between condi-

tions 1a and 2a since these are related to two different constraints in the network.

To start with, condition 1a is influenced by the injection into the storages Sediane Littoral,

Serene Sud and Saline. Based on the definition of climatic capacities32, the maximum poten-

tial relief of congestion in the North-South direction in the summer months varies between

approx. 100 GWh/d in April and 492 GWh/d in August. On individual days, storages may

thus substantially reduce congestion according to condition 1a, or potentially even resolve it

entirely during the summer.

On first sight, these values seem to indicate that one could largely relieve congestion based

on a different use of underground storages. However, storage operation also has to comply

with the 'tunnel constraints', which shall ensure that sufficient gas is put into storage for the

supply of local consumption in the winter months. Consequently, even if shippers are able to

temporarily reduce injection, they can only do so within the limits of the overall injections

required during the summer. Among others, this may also mean that reduced injection on

one day may have to be compensated by increased injection at a later time.

To demonstrate the corresponding effects, Table 19 provides a summary of the required

injections in different cases, and the resulting relief of congestion according to condition 1a.

32

See Annex 1, pp. 35 - 36

-1.000

-500

0

500

1.000

1.500


GW

h/d


We see that that the potential relief ranges between a minimum of 9 TWh and a maximum of

45 TWh, which is equivalent to an average daily relief of 50 to 250 GWh/d. A realistic esti-

mate appears to be much closer to the lower limit, as indicated by the values for the period

April 2009 to March 2010 (19 TWh and 106 GWh/d, respectively).

Total Injection Congestion relief (a)

(TWh)

Aggregate

(TWh)

Average

(GWh/d)

Min. injection

(according to 'tunnel constraints') 26 45 250

Actual injection in 2009/2010 52 19 106

Max. injection (= maximum inventory level) 62 9 50

Sum of climatic capacities 71 N/A N/A

Table 19: Excess summer injection capacity at storages relevant for condition 1a

(a) – Equivalent to difference between sum of climatic capacities and injection in summer

In case of condition 2a, physical congestion is influenced by the storage group Saline only.

In this case, the maximum potential relief ranges between approx. 41 GWh/d in April and

149 GWh/d in August33. In contrast, the climatic injection capacities between mid-April and

mid-October add up to some 21.5 TWh, which is almost twice as high as the maximum in-

ventory level. Moreover, the annual use of Saline has been limited to less than 5 TWh in

recent years and it seems unlikely that Saline will be used as a purely seasonal storage in

future. Even when assuming an annual variation of 5 to 7.5 TWh, the standard definition of

condition 2a would thus over-estimate congestion by some 14 to 16.5 TWh/a, or an average

78 to 92 GWh/d on a daily basis.

In summary, these considerations lead to the following conclusions:

Variations in the daily operation of storages in the south of the GRTgaz area princi-

pally offer a very effective instrument to reduce congestion.

33

Based on some additional analysis carried out by GRTgaz, and in contrast to the information provided in An-nex 2, these values also take into account the potential from Etrez. This additional relief is available in case of net exports to TIGF only, and is limited to 1/3 of the daily net export to TIGF. Since the exit flow to TIGF is greater than 300 GWh/d at almost all times during the summer season in the non-conservative scenario, however, the latter condition is not usually binding in this particular case.


For condition 1a, congestion may be relieved by between 100 GWh/d in April and

almost 500 GWh/d in August. However, storage inventories have to be filled up dur-

ing the summer, such that the average impact will be much lower. Assuming that

shippers will need to inject approx. 85% to 90% of the total inventory (52 – 56 TWh),

actual congestion will be an average 84 – 106 GWh/d less than indicated by the si-

mulation results above. Taken together, these numbers indicate a substantial poten-

tial to reduce structural congestion, although within clear limits. In addition, under-

ground storage has an even larger potential to resolve congestion on individual days

where it may potentially be used to relieve congestion entirely.

In contrast, the maximum effect of underground storage on condition 2a is much

more limited, i.e. close to 150 GWh/d in August but just 41 GWh/d in April. On aver-

age, however, congestion can be expected to be some 78 to 92 GWh/d less than the

violations reported above. Whilst the immediate impact of underground storage on

condition 2a is thus significantly less than on condition 1a, it is just slightly less effec-

tive on average.

In practical terms, the corresponding variations could obviously be realized by ship-

pers modifying the daily injection schedules accordingly. Alternatively, there also

seems to be substantial scope for temporarily shifting the injections between different

storage sites in the Northern and Southern parts of the GRTgaz network. This possi-

bility may be limited, however, by the need to compensate this change by an oppo-

site shift at a later time, which may be problematic in case of structural congestion. In

this context, it is worth noting that the aggregate injection capacity of Sediane Nord

and Serene Nord is roughly comparable to the total injection capacity in the South.

Moreover, even when assuming a storage cycle of 90% to 100% of the inventory lev-

el, Sediane Nord and Serene Nord provide flexibility for an average of 118 to 139

GWh/d additional injections on individual days.

5.2.4 Potential actions at TIGF

As already mentioned above, both condition 1a and 2a are negatively influenced by exports

to the TIGF area. At the same time, scenario 1 is characterized by very high exit flows to

TIGF in the summer, including in the non-conservative scenario (see Figure 25). Conse-

quently, congestion in the North-South direction can obviously be easily reduced by decreas-

ing the exit flow to TIGF. Given the volume of the corresponding flows, it appears that this

congestion might theoretically be resolved by isolated actions at this entry/exit point alone.

A significant share of the exit flow to TIGF is caused by exports to Spain. In this context, it is

worth noting that our simulations are based on the maximum export capacity of 225 GWh/d


to Spain. In contrast, the CRE has informed us that some 60 GWh/d of this export capacity

should be considered as available on an interruptible basis only. As further discussed in

section 5.3.2 below, the existence of interruptible capacity may thus represent an obvious

tool for mitigating congestion in the North-South direction.

Figure 25: Exit flow to TIGF in the non-conservative scenario

5.2.5 Potential actions at Fos

Scenario 1 is characterized by limited imports of LNG, due to the assumption of very high

prices for LNG deliveries. As a consequence, the daily injection from Fos thus largely re-

mains in a range of 200 to 300 GWh/d in the summer season, or some 225 GWh/d on aver-

age. These numbers are in clear contrast to an available entry capacity of 530 GWh/d. On

average, some 300 GWh/d of entry capacity thus remain unused during the summer. Given

that both condition 1a and condition 2a are positively influenced by entry flows at Fos, the

available entry capacity at Fos thus provides for another important means of managing con-

gestion in the North-South direction.

In order to deal with structural congestion, entry flows at Fos might have to be increased for

a prolonged period of time, potentially several weeks or even months in a row. In a situation

like the one characterized by scenario 1, this may conflict with limited deliveries of LNG. As a

result, there is a risk that the ability of using Fos for managing congestion may be strictly

limited by an insufficient supply of gas to this terminal. The successful use of this source

may therefore require certain measures to ensure the availability of sufficient volumes of gas

over an extended period of time.

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5.2.6 Summary

Overall, the analysis in this section leads to the following conclusions with regards to manag-

ing congestion in the North-South direction in the non-conservative scenario:

CCGTs represent a potentially important source of congestion management as they

could provide a relief of up to 165 and 126 GWh/d (in case all concerned CCGTs are

switched off) for congestion in the North-South direction as defined by conditions 1a

and 2a, respectively. Moreover it appears that the levels of congestion reported

above may be over-estimated by approx. 40 – 50 GWh/d on average.

Similarly, reduced injections into underground storage in the South may help to re-

duce congestion by between 100 GWh/d and almost 500 GWh/d for congestion de-

fined by condition 1a, or approx. 40 to 150 GWh/d for condition 2a. Although the im-

pact of storages thus is limited in the spring and fall when climatic capacities are low,

they principally offer a very effective instrument to reduce congestion in the summer

months. However, it should be noted that the use of this flexibility is limited by the

need to re-fill storages during the summer. Consequently, the average relief available

from storages will be significantly smaller. Nevertheless, it appears that the conges-

tion reported above may have been over-estimated by some 84 – 106 GWh/d and 78

to 92 GWh/d for conditions 1a and 2a, respectively.

Reductions of exit flows to TIGF represent an instrument that might even be theo-

retically sufficient to fully resolve congestion in the summer. Moreover, this approach

would probably not face any immediate technical constraints, in particular with a view

to the existence of interruptible export capacities to Spain, which are fully utilized on

a regular basis in this scenario.

Finally, increased entry flows at Fos offer another suitable option which might help to

reduce congestion by up to 300 GWh/d on average in this particular scenario. The

continued use of this instrument would however depend on the delivery of sufficient

volumes of gas to Fos.

Overall, these four different sources easily suffice to mitigate any congestion in the North-

South direction as observed in our simulation. Indeed, Table 20 shows that the maximum

theoretical potential is about two to three times larger than the maximum congestion ob-

served in the non-conservative scenario. In principle, Table 20 thus indicates that GRTgaz

has access to four different sources that can be used to resolve congestion.


Source Condition 1a Condition 2a

CCGT 150 120

Underground storage 100 - 500 40 - 150

Exit to TIGF 300 – 400

Fos (average) 300

Total 850 – 1,350 760 - 970

Table 20: Theoretical potential for relieving congestion from North to South (GWh/d)

As discussed above, the average effect from CCGTs and storages will usually be substan-

tially smaller than the maximum values listed in Table 20. This effect is also visible from Fig-

ure 26 which shows the congestion relief resulting from the actual operation of underground

storages and CCGTs in the non-conservative scenario. We observe that the relief of condi-

tion 1a from underground storage is much more volatile than for condition 2a, which can be

explained by the major difference in the maximum impact visible from Table 20. Overall, the

cumulative reductions are nevertheless much more comparable, i.e. 20 TWh for condition 1a

and 16 TWh for condition 2a.


Figure 26: Decrease of N-S congestion due to impact of storages and CCGT

Finally, Figure 27 shows the resulting impact on congestion from North to South in the non-

conservative scenario. Congestion decreases significantly, leading to a reduction of cumula-

tive congestion between mid-April to mid-October from 46 to 28 TWh. Nevertheless, daily

congestion still exceeds 200 GWh/d on a regular basis.

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Figure 27: Impact of storages and CCGT on congestion from North to South (non-

conservative scenario)

5.3 Approaches for Mitigating Congestion in North-South

Direction

5.3.1 Options for mitigating congestion through actions in the North

Given that France imports substantial volumes of gas in the North during the summer in

scenario 1, it should principally be easily possible to decrease congestion for instance by

reducing import flows at Dunkerque, Taisnières or Obergailbach. But the enumeration of

different entry points already indicates that care would need to be taken to avoid a situation

where a reduced flow at one entry point is compensated by an increased flow at one of the

other locations. Given the geographical proximity and level of interconnection, as well as the

degree of price convergence between the Belgian and German gas markets which already

exists today, this clearly represents a realistic risk. At a minimum, simultaneous actions

would thus be required at all three entry points to ensure that these would really be effective

in reducing congestion to the South.

A second complicating factor results from the fact that approx. 1/3 of aggregate entry capaci-

ty, or more than 700 GWh/d of available entry capacity to the North is not used in this scena-

rio. Even before being able to reduce flows, it would thus be necessary to ensure that the

corresponding volumes could no longer be used by shippers. Given the volume of unused

capacities, this would obviously require massive interventions into the market, irrespective of

whether voluntary or administrated measures are used. In addition, it would furthermore be

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necessary to account for potential variations of exit flows to Switzerland and injections into

underground storage in the North, which would create significant additional uncertainty.

Overall, we therefore conclude that interventions in the North are unlikely to be an effective

and cost-efficient instrument for resolving North-South congestion in this case.

5.3.2 Use of short-term market mechanism or interruptible capacity at

the border with TIGF

As mentioned in section 5.2 above, a reduction of exit flows represents a very effective in-

strument for reducing congestion in the North-South direction. In line with our conclusions in

chapter 4 (see section 4.5), the initial choice would therefore obviously be to rely on short-

term market mechanisms, such as locational trades or capacity buy-back. Given that the

corresponding gas is either sourced from or transported through the GRTgaz network and

that most of it will either be re-exported to Spain or put into storage in the TIGF area, we

would not foresee any fundamental problems in this respect.

However, there are several potential issues to be taken into account:

The successful application of a market-based mechanism requires sufficient scope

for competition; an assumption which may not hold in the TIGF area;

This problem might be further aggravated by the fact that congestion regularly ex-

ceeds 200 GWh/d, which is equivalent to more than 50% of available capacity at this

entry/exit point;

To our knowledge, a robust (daily) reference price for the TIGF area (and Spain)

does not yet exist, which would make market monitoring more difficult.

Whilst these observations do create an obstacle to the application of market-based mechan-

isms, they certainly indicate that such mechanisms should not be used in isolation at this

location. Consequently, any corresponding mechanism should also cover other sources if at

all possible, i.e. Fos, underground storages and/or CCGTs. Indeed, there are no reasons

why locational trades or similar products, such as some form of capacity buy-back, are not

offered for instance from CCGT operators.

In addition, we note that some 100 GWh/d of exit capacity to TIGF have been reserved for

allocation as short term products. An alternative, or supplement, to the application of a mar-

ket-based mechanism might therefore be to convert the corresponding volume into interrupt-

ible capacity. Although this measure would obviously reduce the level of firm capacity avail-

able at this border, it might provide a cost-efficient option to reduce congestion. Moreover, it


would help to avoid situations where short term capacity was made available to the market

even in anticipation of structural congestion but bought back from the market afterwards

(either in the form of capacity buy-back or through locational trades).

Figure 28 illustrates the potential benefits that could be gained from a corresponding reduc-

tion of firm capacity. During the critical summer period, the reduction of firm capacity34 prin-

cipally leads to a directly equivalent decrease in congestion. Although the situation may be

slightly different when taking into account the impact of storage and CCGTs on congestion,

there are no reasons to believe that the outcome would be fundamentally different. Conse-

quently, we would expect a similar reduction, i.e. by 100 GWh/d or some 15 TWh35.

Figure 28: Decreased congestion at reduced exit capacity to TIGF (300 GWh/d)

34

Which has been modeled as a straightforward reduction of exit capacity

35 Based on the observation that a reduction of firm exit capacity in Figure 28 has an impact for approx. 150 days

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5.3.3 Use of interruptible export capacity to Spain

In section 5.2.4 above we have noted that part of the export capacity to Spain, which is

heavily utilized in scenario 1, should be considered as being available on an interruptible

basis only. An alternative to converting part of the exit capacity from GRTgaz to TIGF to

interruptible capacity might therefore be to limit export flows to Spain to the level of firm ca-

pacity in the first instance. Similar to the conversion of firm to interruptible capacities at the

border between GRTgaz and TIGF, this option would not require any direct intervention into

existing capacity rights. Moreover, it would not entail any reduction in the volume of firm

capacities being available to the market. In this context, we note one particular advantage

from the perspective of the French market, i.e. that this option would maintain the full level of

interconnection between the GRTgaz and TIGF areas.

To assess the impact of this option, we have tested another sensitivity case where we have

reduced export capacity from TIGF to Spain by 60 GWh/d, i.e. from 225 to 165 GWh/h. Our

results show that this modification reduces congestion during the summer months, but in a

different way than in case of reduced exit capacity to TIGF. More precisely, whilst the aver-

age reduction of physical congestion is comparable in both cases (approx. 20% of the origi-

nal volume), the interruption of exports to Spain does not seem to result in a tangible reduc-

tion of the maximum level of physical congestion.

This effect is illustrated by Figure 29, which compares the duration curves of physical con-

gestion in the North-South direction between the original case (non-conservative scenario),

the reduction of exit capacity to TIGF by 100 GWh/d and the interruption of exports to Spain

by 60 GWh/d. Similar to Figure 28, this illustration shows that a reduction of exit capacity to

TIGF by 100 GWh/d results in a similar decrease of congestion at time s of high congestion.

Implicitly, this option therefore also leads to a corresponding decrease in the maximum vo-

lume of congestion. Conversely, we still observe more than 50 days with (close to) maximum

congestion in case of reduced exports to Spain.


Figure 29: Duration curves for North-South congestion under different assumptions

on the availability of exit capacity to TIGF / Spain

Based on our analysis, this observation can be explained by the fact that the corresponding

volumes are instead used for injecting gas into the underground storages in the TIGF area.

In other words, whilst high export (i.e. transit) flows to Spain are 'competing' with injections

into the underground storages in the non-conservative case (with full or reduced exit capaci-

ty to TIGF), the reduction of export capacities to Spain implicitly provides additional flexibility

for optimizing the operation of the TIGF storages against daily market prices in the French

market. On many days, the exit capacity, which is no longer needed for exporting to Spain, is

thus instead used to increase injection into the TIGF underground storages. These additional

volumes are then compensated by less injection on other days, resulting in a substantially

higher share of days with low to medium congestion.

In summary, these observations lead to two conclusions: First, our findings indicate that the

limitation of exports to Spain to the level of firm capacity helps to maximize the level of mar-

ket integration between the GRTgaz and TIGF areas, whereas the reduction of exit capacity

from GRTgaz to TIGF may be considered as potentially critical in this respect. Secondly, and

of particular importance for the purpose of this report, however, the interruption of exports to

Spain by up to 60 GWh/d does not appear to be sufficient to provide for a 'guaranteed' re-

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duction of physical congestion in the GRTgaz market area, at least not when focusing on the

most critical days with high volumes of congestion.

In this context, it is furthermore important to consider that the resolution of physical conges-

tion may regularly require a reduction of exit flows from GRTgaz to TIGF that cannot be

achieved through reduced exports to Spain alone. Similar to the case of imports in the North

(compare section 5.3.1), this may lead to a need for buying back exit unused capacity before

being able to ensure an effective reduction of physical congestion. Alternatively, it might

become necessary to exclusively rely on locational trades. However, this would make it more

difficult to include exit capacity or flows into the potential procurement of flow commitments

by monthly tenders, as discussed in the following section.

On balance, we are therefore not convinced that the interruption of exports to Spain to the

level of firm capacity can be considered as an ideal tool. Although our simulations indicate

that this option may be effective in reducing physical congestion in the North-South direction

on average, the remaining uncertainty on daily exit flows implies that it may still be neces-

sary to procure the same volume of flow commitments in case of structural congestion. Con-

sequently, there is a significant risk that the cost of mitigating the North-to-South congestion

would be broadly similar irrespective of whether the export capacity to Spain is 165 GWh/d

or 225 GWh/d. In the remainder of this report, we therefore neglect this option and focus on

the potential conversion of firm to interruptible exit capacities to TIGF instead.

5.3.4 Monthly auctions at Fos

The LNG terminals at Fos are able to provide sufficient capacity which could easily be bid

into a market-based mechanism, for instance in the form of locational trades. However, we

have already pointed out above that the resolution of structural congestion will furthermore

require the availability of sufficient volumes of commodity over an extended period of time. In

this case, it is therefore essential to take into account the particular nature of the LNG busi-

ness. The latter is characterized by a (substantial) delay between the decision to deliver an

additional cargo to a terminal and the actual arrival of the vessel in the destination port.

It therefore appears that the use of day-ahead mechanisms may not be the right choice in

case of structural congestion. Conversely, given the timelines for the scheduling of LNG

cargoes, early actions will likely be required to ensure a continued supply. At the same time,

it also seems beneficial to use the inherent flexibility of the LNG market, which allows for the

redirection of cargoes at relatively short notice from typically one to several weeks. In order

to ensure an optimal balance between the partially competing objectives of flexibility, firm

commitments and scope for competition, it therefore appears useful to use procedures that

are aligned with the general planning schedule for deliveries to the LNG terminals at Fos.


More specifically, we recommend considering the application of monthly tenders, based on

the following general principles and considerations:

Tenders should serve to purchase flow commitments from shippers, which oblige

successful tender participants to deliver a given volume of LNG to Fos and inject into

the network in compliance with the normal operating schedules at Fos;

To enable a purely market-based evaluation and selection of offers, the tender

should be based on a standardized product, including in particular the supply of the

corresponding gas to the network once it has been unloaded at the LNG terminal;

Offers should generally be selected based on the offered price (only);

Participation in the tender should be open to all vessels that are qualified for delivery

to Fos, provided that the corresponding party or shipper has signed the relevant con-

tractual (framework) with GRTgaz and the LNG operator, or commits himself to do

so; and

In order to enable the participation of parties that have not reserved terminal capaci-

ty, the tender should ideally be initiated or at least carried out after the confirmation of

the initial monthly LNG schedule, in order to ensure that free LNG slots are known to

the market and potential bidders.

We believe that the proposed concept is generally compatible with the existing arrange-

ments at Fos. Moreover, when properly designed, a corresponding tender mechanism would

enable the participation of new entrants without firm capacity reservations, which might be

an important precondition for increasing the scope for competition.

In contrast, the use of a monthly mechanism may be considered as relatively risky as the

TSO would effectively become vulnerable to the risk of insufficient offers. An alternative

might therefore be to instead apply a longer timeframe, for instance a longer notice time (2 –

3 months) or the use of longer procurement periods of for instance 3 or 6 months. The latter

would however involve substantially higher uncertainty on the (opportunity) costs of future

deliveries, which shippers would likely factor into their offers in the form of higher prices.

Moreover, both options would principally imply that participation in the tender was open to

shippers with existing capacity bookings at Fos only, which would likely restrain potential

competition considerably.

Finally, a prolonged procurement period would also increase uncertainty on the expected

scope of congestion. This in turn might force GRTgaz to purchase excessive volumes of flow

commitments, thereby further increasing the costs of the tender. Conversely, the proposed


use of monthly tenders would enable the TSO and shippers to adjust requested volumes or

prices to actual needs and to the current market environment.

In order to increase the scope for competition, it might furthermore be worth expanding the

tender mechanism to other parties and/or locations. For instance, we could imagine that the

tender for LNG deliveries to Fos was combined with a simultaneous tender for capacity buy-

back for instance at TIGF and for exit capacity to CCGT plants. Although one might also

purchase the corresponding products in the very short term (i.e. day ahead), the establish-

ment of an enlarged market place for products with a 'medium term horizon' (e.g. one month)

could be instrumental in creating the basis for effective competition for the delivery of the

corresponding services.

One critical issue in the design of a corresponding mechanism would obviously be the need

to provide for an appropriate balance between the desire of (incumbent) shippers for flexibili-

ty on the one hand, and the TSO's need for firm commitments on the other hand. In combi-

nation with the objective of enabling or even promoting the participation of new entrants, it

might be important to impose certain restrictions on the operational planning of incumbent

capacity holders, such as the provisions for the short-term 'use-it-or-lose-it' principle as al-

ready in place for the LNG terminals operated by Elengy36 and STMFC. However, the cor-

responding provisions might have to be checked to ensure that they provide an appropriate

level of firmness, in order to ensure that any unused capacity can be made available to the

market for the following month. In addition, it should be assessed whether such restrictions

are acceptable to shippers.

Conversely, if a shipper decided to nominate an additional cargo for the following month, it

might be desirable to establish a fixed obligation to actually use this capacity, in order to

prevent hoarding as far as possible. Given the different relationships between GRTgaz, the

LNG terminal operator and shippers, the implementation of a corresponding obligation may

prove difficult. However, one possible option might be to increase the penalty for late cancel-

lation of a scheduled unloading operation as specified in Article 9.9 in the General Terms &

Conditions for the access to Elengy's LNG terminals37.

Finally, one obvious risk is related to the ability of shippers to artificially decrease their initial

nominations for LNG cargoes, in order to force the TSO to engage in flow commitments.

This is a fundamental problem which cannot be avoided in a market-based mechanism.

Nevertheless, potential competition from exit capacity to TIGF and CCGTs provides at least

some protection in this respect, in particular when considering the reduced levels of conges-

36

See Elengy. Contract providing access to the LNG terminal Annex 1 General Terms and Conditions. Version of 1 January 2010. Article 6.2

37 Elengy. Contract providing access to the LNG terminal Annex 1 General Terms and Conditions. Version of 1

January 2010


tion identified at the end of the previous section. Moreover, the short-term use-it-or-lose-it

provision mentioned above may also reduce corresponding incentives as the shipper would

otherwise bear the risk of losing his or her delivery slots.

5.4 Congestion in South-North Direction

The two previous sections have focused on congestion in the North-South direction, which is

characterized by potentially structural constraints and hence requires particular attention. In

contrast, congestion in the South-North direction, which is in the focus of this section, has a

very different nature. As illustrated by Figure 30 we have observed corresponding issues in

one single situation only, i.e. at periods of very cold winter temperatures in scenario 2 (cheap

LNG) with low take-or-pay obligations. Moreover, even in this case, problems only arose on

8 days (2.1% of time).

Figure 30: Congestion in South-North direction in scenario 2 (low Take-or-Pay)

Nevertheless, as already emphasized in the context of the original congestion analysis in

section 3.4 above, this congestion pattern may lead to substantial problems on individual

days, with violations of more than 100 GWh/d being observed. In addition, these issues can

be expected to increase on even colder days, potentially growing by another 300 GWh/d on

days with an average temperature of -11.1 °C. Although the probability of corresponding

instances can be considered as very low, this nevertheless represents a serious risk which

has to be handled in a combined market area as well.

Conversely, it appears that CCGTs may help to at least partially mitigate congestion. The

mathematical definition of this constraint is based on the binary assumption of all potentially

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helpful units in the South being out of operation. Due to the very high sensitivity of French

electricity demand to cold temperatures, days that are critical for this congestion pattern will

be characterized by record-high electricity consumption as well. In addition, one has to con-

sider the lack of other peak load plants in France as well as the fact that reserve margins in

the German electricity market have been significantly reduced as a result of the recent deci-

sion for a nuclear phase-out in Germany. As in the past, we would generally expect very

high electricity prices in France on such days and that gas-fired plants will be required to run

to support the power system.

Under these circumstances, the assumption of zero CCGT production clearly appears to be

overly pessimistic. As a matter of fact, a more realistic assumption would probably be closer

to these plants running at full output. Nevertheless, one also has to consider the fact that

some of the plants may have to run at reduced capacity to provide ancillary services to the

power system, as well as the risk of unplanned outages. Consequently, CCGT production

may very well be below nominal capacity even on corresponding days, in particular during

the night hours as they will need to follow the hourly profile of electricity consumption. At the

same time, cold temperatures will also cause an increased diurnal profile for gas consump-

tion, in combination with very high consumption in general. In this case, a further increased

need for diurnal flexibility may certainly be critical.

Based on these considerations, we take the assumption of CCGTs operating at 50% of their

nominal capacity. This would relieve the congestion shown in Figure 30 by approx.

80 GWh/d, or by between 50% and 100%. Nevertheless, although CCGTs could potentially

reduce congestion by up to 165 GWh/d, these numbers contrast with an additional risk of a

further 300 GWh/d congestion as mentioned above. Although we expect a potentially signifi-

cant relief from CCGT, it is therefore clear that the gas network cannot rely on this potential

source alone.

In order to consider other options for reducing these congestion patterns, it is worth noting

that this constraint is defined by the following condition:

Max Entry Fos – Exit TIGF + Entry Montoir.

Consequently, congestion can be resolved by reducing either the entry flows at Fos and

Montoir, or imports from TIGF. Fortunately enough, the problems observed in scenario 2

always coincide with significant entry flows in the South. More precisely, LNG terminals are

injecting at more than 70% of available capacity, or more than 650 GWh/d, whilst imports

from TIGF are also very high, i.e. at or close to the maximum of 225 GWh/d. In total, there is

thus scope for reducing entry flows in the South by roughly 900 GWh/d, which clearly is

more than sufficient to resolve congestion.


When assuming a prolonged cold spell, one might theoretically encounter problems as an

extended reduction of the entry from LNG terminals could make it impossible to unload

scheduled cargoes arriving at the terminals. However, there are two reasons why we believe

that such limitations may not be critical in reality. First, given the temporary nature of ex-

treme cold spells, it may be possible to keep incoming vessels on the sea for a limited period

of time, although this would cause additional costs for the vessel as well as opportunity costs

due to the need to delay additional journeys. Secondly, prices in North-Western Europe can

generally be expected to be very high during periods of cold spells, such it may very well be

possible, or even profitable, to redirect incoming vessels to other European terminals, sub-

ject to the availability of unused unloading capacity.

Overall, we thus conclude that it should be possible to manage congestion in the South-

North direction by means of short term market interventions on a daily basis. Given the

choice between three different sources (Fos, TIGF, Montoir), it should principally be possible

to rely on locational trades in this case. One potential risk in this respect is however that

shippers might try to exploit such situations by artificially increasing their initial entry nomi-

nations, in order to force GRTgaz to intervene and pay shippers to restore their nominations

to acceptable levels.

5.5 Congestion in West-East Direction

In comparison, congestion from West to East appears to be the least critical. To start with, it

occurs with a limited frequency in a few scenarios only, i.e. about 15% of the time in scena-

rio 1 with low take-or-pay obligations or just a couple of days in scenario 3. Moreover, the

degree of congestions is limited, with an average of below 10 GWh/d or a maximum value of

60 GWh/d. Particularly in comparison with potential congestion in the North-South direction,

these volumes appear relatively small.

In terms of physical options for mitigating this type of congestion, the potential relief from

either storages or CCGT seems to be marginal, although CCGT production may help to re-

solve some of the extreme values observed. Nevertheless, a closer analysis of the simula-

tion results reveals that this congestion pattern always seems to coincide with congestion in

the North-South direction. This can also be explained by the fact that the corresponding con-

straint is defined by minimum entry flows at Fos, which are critical for congestion in the

North-South direction as well.

It is thus not surprising to see that this congestion disappears in those scenarios with re-

duced congestion in the North-South direction. In other words, these results indicate that this

type of congestion will usually be implicitly resolved by measures taken to deal with conges-

tion in the North-South direction. One may thus assume that no specific actions are required


in most cases. Moreover, in the worst case, any remaining problems could probably be re-

solved through locational trades at Fos, in order to increase the entry flow by a limited

amount.

In summary, we therefore do not see the need for any specific arrangements for this type of

congestion.

5.6 Cost Assessment

5.6.1 Congestion in North-South Direction

In sections 5.2 and 5.3 above, we have analyzed several options and approaches for miti-

gating structural congestion in the North-South direction. This discussion has shown that

different instruments may have to be combined in order to safely handle congestion. Before

assessing the costs of the different options, it therefore seems useful to consider a summary

of the volumes of congestion to be managed.

When considering the non-conservative scenario with a reduced seasonal spread, we have

seen that physical congestion in the non-conservative case may amount to approx. 300

GWh/d in the summer season. As shown in Figure 27 on p. 87, the actual level of congestion

may be significantly lower due to the operating pattern of storages and CCGTs. Depending

on whether one accounts for the potential impact of CCGTs or not, the average level of con-

gestion between mid-April and mid-October may amount to somewhere between approx.

150 GWh/d and 27.5 TWh, or 190 GWh/d and 34 TWh.38 To avoid overly optimistic assump-

tion, we subsequently take the assumption that the remaining level of congestion amounts to

200 GWh/d or 34 TWh.

In principle, it would thus be necessary to manage the corresponding volume, i.e. 200

GWh/d or 34 TWh, through a mix of short and medium-term market-based mechanisms.

However, we have also pointed out that the conversion of unsold exit capacity to TIGF would

make it possible to reduce congestion by another 100 GWh/d, which would lead to a remain-

ing volume of 17 TWh over a period of 180 days.

Table 21 summarizes the resulting estimates on the need for congestion management to be

realized through market-based mechanisms. In this context, it should be noted that these

values are based on an original physical congestion of less than 275 GWh/d. In contrast,

congestion could increase by up to 500 GWh/h when assuming reduced take-or-pay obliga-

38

In contrast, daily congestion may still reach 300 GWh/d in both cases.


tions, or even by 550 GWh/d in the absence of take-or-pay obligations. These ranges high-

light a significant degree of uncertainty and show that the actual requirements may potential-

ly be more than 200 GWh/d higher than indicated by Table 21.

Daily need

(GWh/d)

Cumulative need

(TWh)

Base case 200 34

Alternative case (a)

100 (b)

17

Table 21: Assumed requirements for market-based congestion management in North-

South direction

(a) – Based on conversion of 100 GWh/d unsold firm capacity to interruptible capacity

(b) – Plus 100 GWh/d in the form of interruptible exit capacity to TIGF

To start with, Box 1 summarizes our assumptions on the loss of revenues, which results

from the sale of interruptible instead of firm capacity. These estimates are based on the cur-

rent price of firm capacity from GRTgaz to TIGF, assuming that 60% of the total value can

be attributed to capacity in the summer season and a 50% reduction to account for the risk

of interruption. Under these assumptions, the total opportunity costs of both TSOs would

amount to 4.2 M€/yr if all capacity (100 GWh/d) was marketed as interruptible capacity. Ob-

viously, actual opportunity costs may be substantially higher or lower, depending on whether

available capacity would have been sold before and is sold after the conversion, and wheth-

er it is sold at a regulated price or via auctions.

Costs of firm capacity 150 €/(MWh/d)/yr

(75 and 65 for GRTgaz and TIGF, resp.)

Cost of firm summer capacity 84 k€/(GWh/d)/yr

(60% of total price)

Costs of interruptible capacity 42 k€/(GWh/d)/yr

(Assuming 50% risk of interruption)

Loss of revenue (100 GWh/d) 4.2 M€/yr

Box 1: Cost Estimates for Conversion of Firm to Interruptible Exit capacity to TIGF

Next, we consider the case of a market-based reduction of exports to TIGF, for instance by

means of locational trades or capacity buy-back. This estimate is based on the spread be-

tween the average spot prices in Spain (20.5 €/MWh) and North-Western Europe

(17 €/MWh) during the summer months. We see that GRTgaz would have to pay between

59.5 and 119 M€/yr for resolving congestion, which is substantially more than the opportunity

costs of interruptible capacity discussed before. Moreover, it should be note that this esti-


mate obviously is highly sensitive to the price spread between Spain and France as well as

to the bidding behavior of shippers. In this particular case, we have assumed that shippers

would offer capacity or counter trades at the existing spot spread, which is an optimistic as-

sumption that is unlikely to hold in practice. Moreover, we also note that these estimates do

not include any potential costs of counter trades which may be required to offset interven-

tions at this point.

Average spread Spain – NW-Europe 3.5 €/MWh

(summer months)

Base case (34 TWh) 119.0 M€/yr

Alternative case (17 TWh) 59.5 M€/yr

Box 2: Cost Estimates for Market-Based Actions at border to TIGF

The non-conservative scenario has assumed the same price level for imports of LNG gas to

Fos and for spot deliveries to the Spanish market. Consequently, a valuation of the potential

costs for interventions at Fos would result in the same values as for TIGF when using the

scenario assumptions. As an alternative, we therefore consider the development of price

indices for spot and/or short-term deliveries of LNG to different destinations.

As a first step, Figure 31 shows the development of various price indices between February

2009 and May 2011. This picture shows that short-term deliveries to Japan and Korea have

been traded at a premium to Europe, as represented by the NBP. Between late 2009 and

early 2011, this difference amounted to approx. 2 $/MMBtu, or 5 €/MWh39. In recent months,

i.e. in the time between the events at Fukushima and September 2011, this premium has

increased to 6 $/MMBtu, or 15 €/MWh. Given that scenario 1 is based on the assumption of

high prices for LNG, i.e. a premium for Asian LNG, the former estimates provide a good ba-

sis for our own calculations.

39

At an exchange rate of 1.35 USD to the Euro


Figure 31: Development of different spot indices 2009 – 2011

Source: Platts

When considering the extreme spread between Japan and Europe, one might assume that

all LNG cargoes were diverted to Asia, which is obviously not the case. Besides the potential

impact of take-or-pay obligations, it is also important to note that the market price for North

East Asia as shown in Figure 31 is based on LNG deliveries from the Middle East. In con-

trast, the French market can also be supplied from other sources, including Africa. For the

situation in recent months, we therefore consider a potential diversion of African cargoes to

Japan40. Based on the assumptions shown in Box 3, this alternative approach results in spe-

cific costs of between 2.25 and 4.5 €/MWh.

Spread Japan-Korea – South Western Europe 3.9 $/MMBtu

Additional shipping costs to Japan

Algeria 3.0 $/MMBtu

Nigeria 2.1 $/MMBtu

Premium for deliveries to Japan(a) 2.25 to 4.5 €/MWh

Box 3: Cost Estimates for Market-Based Actions at border to TIGF

(a) – Based on an assumed exchange rate of 1.35 USD/EUR

All estimates based on recent quotations in Platts LNG Daily

Finally, Table 22 presents the resulting estimates for the total costs of resolving North-South

congestion in the non-conservative scenario. Depending on the case and approach consi-

dered, costs may vary between 38 and 170 M€/yr, which obviously represents a very high

40

Without accounting for the opportunity costs for the additional journey time.


degree of uncertainty. Moreover, we again observe a marked difference between the base

and the alternative case. Whilst our estimates vary between 38 and 85 M€/yr for the alterna-

tive case, they are twice as high for the base case.

All values in M€/yr Base case Alternative case

Spread JKM – NBP 170 85

Diversion of African cargo 76.5 - 153 38.3 – 76.5

Table 22: Summary of cost estimates for actions at Fos (N-S congestion, scenario 1)

5.6.2 Congestion in South-North Direction

As discussed above, South-North congestion may occur at times of extreme cold spells only.

Given the correlation between temperature and gas prices, it therefore seems reasonable to

expect that such situations will be characterized by above average or even very high prices

in the spot market. Moreover, we have argued above that this type of congestion will have to

be resolved by means of reduced entry flows at Fos, Montoir or from TIGF. Consequently,

shippers may face potentially significant opportunity costs when being forced to reduce their

sales into the spot market.

It is of course not possible to precisely estimate the corresponding price differences as ex-

treme situations may lead to extreme price movements. To gain an indication of the asso-

ciated risk, Figure 32 presents the duration curve of opportunity costs, which shippers would

have faced when being forced to delay their sales by up to one week over the past eight

years. One can easily see that the corresponding risk mostly stays below 10 €/MWh but may

exceed values of 20 €/MWh or even 40 €/MWh.


Figure 32: Opportunity costs for delayed sales in the wholesale gas market (Zee-

brugge, 2003 – 2011, delay of 1 week)

Given that South-North congestion is linked to exceptional situations, we believe that it is

also necessary to consider potentially extreme price movements. Table 23 therefore pro-

vides a summary of the probability of such events at three relevant hubs, i.e. Zeebrugge,

TTF and NCG. Obviously, Zeebrugge, which has the longest history and is closely linked to

the British gas market, bears the highest risk of extreme price fluctuations, whilst there have

not been many cases of major short-term fluctuations at NGG in the past 2 years.

0.00

10.00

20.00

30.00

40.00

50.00

60.00

7-d

ay p

rice

sp

read

(€/M

Wh

)

Cumulative time

Maximum loss resulting from delayed short-term sales(Zeebrugge, 2003 - 2011)


Price decline Hub

(1 week,

€/MWh )

Zeebrugge

(‘03 – ’11)

TTF

(‘03 – ’11)

NCG

(‘09 – ’11)

10 2.3% 0.9% 0.0%

20 0.7% 0.2% 0.0%

30 0.3% 0.1% 0.0%

40 0.2% 0.1% 0.0%

Table 23: Probability of significant price declines over a period of one week at se-

lected hubs in North-Western Europe

Based on these considerations, Table 24 presents a summary of the resulting cost esti-

mates, in cases where the specific costs from Table 23 are applied to a cumulative conges-

tion volume of approx. 500 GWh. Depending on the assumed price volatility (perceived risk),

congestion management may thus create costs of somewhere between 5 and 20 M€/yr.

Apart from the uncertainty related to the underlying prices, it is important to note that the

total volumes of commodity are subject to substantial uncertainty as well. For example, it is

quite likely that significant additional volumes might be required in winter with even colder

and/or or longer / more frequent cold spells. Conversely, costs can be expected to be zero in

most years, which are characterized by normal or even warm winters.

Price spread

(€/MWh)

Annual costs

(M€/yr)

10 5

20 10

40 20

Table 24: Potential costs of South-North congestion (0.5 TWh/a)

5.6.3 Congestion in West-East Direction

As discussed in section 5.5, we believe that this type of congestion will normally be implicitly

resolved through measures that are required to deal with congestion from North to South.

Consequently, we refrain from any separate cost estimates but refer to section 5.6.1 instead.


5.6.4 Costs of Interactions with Other Infrastructure Operators

In the previous sections, we have exclusively considered the potential costs of market-based

mechanisms, such as locational trades, flow commitments or capacity buy-back, as well as

the potential conversion of firm to interruptible capacities at the border between GRTgaz and

TIGF. In contrast, we have not explicitly considered a range of other measures that have

been addressed in chapter 4, such as:

TSO-contracted storage (see section 4.2.8);

Locational swaps (section 4.2.9);

TSO-to-TSO swaps (section 4.2.10); and the

Re-routing of flows (section 4.2.11).

With regards to TSO-contracted storage, we have explained above (see section 5.2.3) the

limitations of using underground storage for resolving physical congestion in the most critical

case, i.e. structural congestion in the North-South direction in scenario 1. For these reasons,

we do not believe that the option of TSO-contracted storage would appear to represent for

mitigating physical congestion in the particular case of the merger between GRTgaz North

and GRTgaz South. Consequently, we also refrain from any cost estimate in this respect.

Nevertheless, our analysis has also shown that the operation of underground storage may

potentially have a significant impact on physical congestion on individual days. As further

discussed in chapter 6 we therefore believe that the option of locational storage swaps

represents a potentially very promising instrument that should be further studied. By its na-

ture, this option does not require any direct interventions into the (aggregate) use of under-

ground storages by shippers. In contrast, it can simply be achieved by deciding on the re-

gional distribution of injections and/or withdrawals within the framework of the overall

nominations by shippers on a given day41. Given that the daily volumes are small in compar-

ison to the total injections or withdrawals in the summer and winter seasons, respectively,

isolated actions on individual days, or even for a number of days in rows, do therefore not

appear to be critical such that they are not associated with any substantial technical and/or

commercial risks for the storage operator.

In our view, the costs of this instrument would be largely limited to the incremental variation

in compressor costs. Since we expect that these incremental costs would be limited42 we

assume that locational storage swaps as described above would principally be available at

41

Obviously subject to the need to take into account technical constraints linked to each physical storage site

42 This assumption may have to be confirmed by the storage operator.


very limited costs. For these reasons, we believe that the costs of locational storage swaps

would be strictly limited and largely negligible in comparison with the cost ranges identified in

the previous sections.

Concerning TSO-to-TSO swaps and the re-routing of flows, we have already argued in chap-

ter 4.5 above that these mechanisms may help to reduce congestion in certain cases but

that they cannot be relied upon. As a consequence, we regard these two options as supple-

mentary instruments that should be considered in practice. However, apart from the uncer-

tain availability, these instruments should be used only when they help to reduce the costs of

the 'standard' solutions discussed above. As a consequence, one may argue that the use of

TSO-to-TSO swaps and the re-routing of flows may only help to reduce the cost estimates

presented above, but that they should not result in a tangible cost increase.

This view is also confirmed by the fact that TSO-to-TSO swaps should only be used where

both TSOs have access to sufficient flexibility, or where they are able to offset the corres-

ponding volumes through local transactions (e.g. in the day-ahead or within-day market). By

definition, the costs of such transactions should not be fundamentally different from the costs

of locational trades. Consequently, one can consider that these costs are implicitly covered

by the cost estimates for short-term market mechanisms presented in the previous section.

Conversely, we have already mentioned in section 4.2.11 that the costs for the re-routing of

flows are effectively limited to the incremental cost of compression (if any). The costs of

compression are typically limited to a few percent of the transported commodity, which con-

firms our view that these costs can be considered as negligible in comparison with the other

cost ranges identified above.


5.7 Summary and Recommended Options

This chapter has analyzed the impact which variations of entry and exit flows at different

locations may have on the different congestion patterns, in order to identify options for re-

ducing physical congestion. In a second step, we have then combined these findings with

the potential mechanisms which have been discussed in chapter 4, in order to develop a set

of appropriate measures that are able to deal with physical congestion in a robust and effi-

cient way. For each type of congestion, we have finally assessed the costs which may be

expected under application of the corresponding mechanisms.

To start with, our analysis has shown that the need to apply conservative assumptions has

resulted in a significant overestimation of the level of physical congestion in the North-South

direction (reported in chapter 3). In fact, when considering realistic operating patterns for

underground storage and CCGTs, the average degree of congestion decreases by some 40

to 76 GWh/d during the summer season. These findings indicate that the average need for

physical interventions is significantly lower than initially indicated in chapter 3. Nevertheless,

we emphasize that this positive effect is principally limited to the cumulative volume of inter-

ventions over time. In contrast, the scope of the maximum interventions required on individ-

ual days decreases only marginally. Hence, the overall impact is thus largely related to limit-

ing the expected costs of congestion, but it cannot replace the need to have access to

sufficient volumes of flexibility on a daily basis.

Taking these considerations into account, we emphasize the following key observations with

regard to the analysis of physical options for congestion management:

In general, it appears that all types of congestion can be managed by sufficient vo-

lumes of flexibility that are available to the network at different locations. Conse-

quently, our analysis suggests that there is generally sufficient scope for the applica-

tion of a market-based mechanism. In particular, our analysis indicates that GRTgaz

does not seem to depend on any single source for relieving congestion under normal

circumstances. Consequently, it appears that the market merger could be imple-

mented without far-reaching administrated restrictions, at least within the framework

of normal operating conditions.

Nevertheless, the most critical situations are linked to entry/exit flows at two to three

specific locations, namely Fos, TIGF and, to a lesser extent, Montoir. In the particular

case of structural congestion in the North-South direction, the potential scope of con-

gestion may well exceed the flexibility that can be made available (at reasonable

costs) at individual locations. The simultaneous and integrated use of multiple in-

struments at several locations, including Fos and TIGF, thus appears as an essential

precondition for successfully managing congestion by market-based mechanisms.


Apart from entry and exit flows at Fos, TIGF and Montoir, underground storages and

CCGTS may also provide valuable contributions for relieving congestion in the North-

South direction. CCGTs may potentially help to reduce physical congestion on indi-

vidual days by up to 120 to 150 GWh/d. Similarly, underground storages can tempo-

rarily relieve network constraints by up to 150 to 500 GWh/d in the summer, although

the impact is much more limited in the spring and fall. Between mid-May and mid-

September, it would thus principally be possible to fully resolve congestion by adjust-

ing the injection into underground storages, but only on individual days or for a li-

mited time.

In terms of congestion management mechanisms, we principally believe that most con-

straints can be resolved through short-term measures on a daily basis, such as locational

trades and capacity buy-back. To foster integration with the general wholesale market, prefe-

rence should generally be given to locational trades. For reductions of exit flows, such as for

exports to TIGF or off-take by CCGTs, capacity buy-back may represent a more appropriate

approach. As an alternative, GRTgaz may therefore also consider the use of re-nomination

trades, which may be used in place of locational trades but can effectively replace capacity

buy-back as well.

Due to the potential structural nature of North-to-South congestion in the summer, additional

measures may be required to ensure the availability of sufficient gas at Fos. We therefore

propose to consider the application of monthly tenders as an additional mechanism to en-

sure the viability of market-based mechanisms also in the short term. To increase the scope

for competition, such tenders should be open for different products, such as flow commit-

ments at Fos and capacity buy-back for exit capacity to TIGF.

Thirdly, it may be worth considering the possibility of converting unsold firm exit capacity

to TIGF into interruptible capacities. The major rationale for this idea is the fact that the

allocation of the corresponding capacities might otherwise further increase congestion and

hence require an equivalent volume of interventions, i.e. additional costs. Conversely, the

use of interruptible capacities would create a highly effective instrument at managing con-

gestion at strictly limited costs to the TSO(s). Nevertheless, its potential application would

have to be weighted against other over-arching objectives, such as the competitive position

in the TIGF area or more generally integration between the GRTgaz and TIGF market areas.

In addition to these three major options, the high effectiveness of underground storage on

congestions indicates that locational storage swaps, as originally discussed in section

4.2.9, may also represent a valuable instrument. This option, however, is discussed in more

detail in the following chapter, which also contains a more detailed explanation of each of the

other proposed measures.


Finally, Table 25 presents a summary of our estimated ranges for the overall costs of con-

gestion management in each of the three scenarios. This summary shows that congestion in

the North-South direction may create significant costs, reaching up to € 170 million per year

in certain situations. Conversely, Table 25 also shows that costs may be much smaller, or

even largely negligible, in other cases.

These wide ranges essentially reflect the major degree of uncertainty on the future develop-

ment of the French, European and worldwide gas markets, which cannot be predicted with

certainty. Nevertheless, it seems safe to assume that, on average, the costs of a market

merger will be significantly smaller than indicated by the upper estimates in Table 25. This

obviously is the case for scenario 2 where substantial costs are expected in very cold years

only. Similarly, the results for scenario 1 are based on a specific set of assumptions which

may not become true in reality. Nevertheless, it is also true that our simulations have shown

cases with even higher degrees of congestion, which would probably result in additional

costs. The numbers shown in Table 25 therefore aim at presenting a reasonably realistic set

of outcomes which may be encountered in practice.

Scenario 1 Scenario 2 Scenario 3

Congestion

pattern

Base Case Alternative

Case(a)

Normal / Warm

year

Cold

year

North-South 76.5 - 170 38 - 85 - - -

South-North - - - 5 - 20 -

West-East - - - - -

Total 76.5 - 170 38 - 85 - 5 - 20 -

Table 25: Estimated ranges of overall cost for congestion management in different

scenarios

(a) – Based on use of interruptible capacities to TIGF, but without consideration of the asso-

ciated (opportunity) costs

Finally, we note that the issue of physical congestion in the North-South direction, which we

have addressed above, does not result from the market merger alone. Indeed, our analysis

has shown that physical congestion is driven to a considerable extent by consumption in the

South of France and exit flows to the TIGF area. Both are likely to increase as a result of

new CCGTs being constructed in the South and additional interconnector capacity becoming

available from GRTgaz to TIGF and further on to Spain.


Even in the absence of the market merger, the planned investments into CCGT and inter-

connector capacity may thus lead to additional constraints for the gas market in the GRTgaz

South zone. In particular, limited capacity on the North to South link may create additional

constraints for the use of the LNG terminals at Fos. More precisely, shippers may be re-

quired to ensure an increased level of LNG deliveries to Fos in this case, even under ad-

verse market situations as in Scenario 1 of our market simulations. Similar, shippers might

be forced to reduce exit flows to TIGF (or compensate them through increased entry flows at

Fos) under such circumstances, in order to ensure a balanced portfolio in the South zone.

Overall, these considerations illustrate that the need for corresponding restrictions does not

result from the market merger. Instead, these restrictions are caused by physical constraints

in the network and the overall market situation in Europe, which can be believed to be iden-

tical with or without the market merger. As such, the need for the physical measures dis-

cussed in this chapter would arise in any case. The main impact of the market merger would

thus be that these restrictions and the associated costs would become explicit and easily

visible, whilst they have to be internalized by certain shippers in the status quo.

Conversely, this also means that the corresponding shippers would clearly benefit from the

market merger. Namely, they would no longer be constrained by such restrictions in a com-

bined market area. Instead, they would be free to optimize their portfolio and benefit from

potential arbitrage possibilities between different entry and exit points in the entire GRTgaz

area, which may not be possible in the current setting with two separate market areas. In

addition, the market merger should generally make it easier for new entrants to enter the

market in the current South zone, and local customers might benefit from access to a more

liquid market and increased competition. Although these benefits have been beyond the

scope of this study, they should clearly be considered when assessing the cost estimates

presented in Table 25.


6. Recommendations

6.1 Proposed Measures for Enabling the Market Merger

Chapter 4 has assessed a number of principal mechanisms that can be applied to realize a

joint market area even in the potential presence of physical congestion. As a result of this

discussion, we have identified a number of suitable options and indicated the way in which

different approaches may be required for different types of congestion. This analysis has

been supplemented by chapter 5, which has specifically assessed the possibilities, con-

straints and costs associated with each of the congestion patterns identified by GRTgaz.

As a result of the individual parts of the overall analysis in this study, we have identified a set

of different measures which we recommend for consideration to facilitate the intended mer-

ger of the market areas GRTgaz North and South. As illustrated by Figure 33 these meas-

ures include the following:

As the key instrument for managing physical congestion on a daily basis, we recom-

mend the use of short-term market mechanisms, such as locational trades or ca-

pacity buy-back;

To ensure the robustness of the short-term market mechanisms, we furthermore rec-

ommend providing for the option of a supplementary medium-term market mechan-

ism, which can be used in cases of structural congestion from North to South, i.e. in

order to make sure that sufficient flexibility is available to the TSO on a daily basis;

Due to the high effectiveness of underground storage in temporarily relieving even

high levels of physical congestion and with a view to limiting the costs of congestion

management, we thirdly believe that it may be worth considering the application of

locational storage swaps and the potential conversion of firm to interruptible ex-

it capacity to TIGF;

Finally, we suggest that this core set of mechanisms should be supported by some

supplementary measures, such as the development or improvement of 'operating

agreements' between GRTgaz and other infrastructure operators, or the option of

direct interventions by GRTgaz as a measure of last resort, i.e. in the form of re-

strictions on certain nomination patterns.


Figure 33: Overview of proposed measures to enable the market merger

Based on our analysis in chapter 5, we conclude that GRTgaz should generally be able to

resolve (non structural) physical congestion through short-term market mechanisms, even in

case of 'extreme' congestion on individual days or for limited periods of time. Due to our

general preference for market-based mechanisms (compare chapter 4), we believe that such

short-term market mechanisms should thus be regarded as the primary tool for congestion

management on a day-to-day basis.

Nevertheless, in chapters 4 and 5, we have also explained the risk of structural congestion in

the North-South direction and the associated risk of a shortage of energy (rather than capac-

ity). Since the latter is related to the lead times for the scheduling of LNG cargoes it is there-

fore essential that the short-term mechanism is supported by an appropriate medium-term

mechanism, to ensure the availability of sufficient volumes of energy on a day-to-day basis.

Again, we believe that it should be possible to rely on a market-based mechanism in this

respect, such as monthly tenders for flow commitments and/or capacity buy-back.

As also indicated in Figure 33 the combination of short- and long-term market mechanisms

should therefore be considered as the core part of congestion management in our view.

However, our analysis in chapter 5.2.3 has also revealed that variations in the daily opera-

tion of underground storages, and their regional distribution, principally offer a very promis-

ing option. Although such variations are unable to resolve structural congestion, they never-

theless represent a highly effective instrument for temporarily relieving physical congestion.

Consequently, it definitely seems worth to consider the best ways for exploiting the corres-

Other supplementary measures


(measure of last resort)

Flexibility available through

cooperation with other TSOs

Medium-term

market mechanism

Short-term

market mechanism

(Locational storage swaps, conversion

of firm to interruptible capacity)

Potential supporting mechanisms


ponding benefits, for instance through the provision of locational storage swaps or potentially

even the offering of a temporary lease or lending service by Storengy.

Similarly, our analysis has shown that a limited conversion of firm exit capacity to TIGF to

interruptible capacity would represent an efficient and highly cost-effective tool for managing

physical congestion in the North-South direction. Although a comprehensive analysis of the

resulting impact on the gas market in the TIGF area has been beyond the scope of this

study, we therefore recommend that the potential application of this measure should be

carefully considered as another tool to support the core set of market-based mechanisms.

In chapter 4.5, we have argued that it may be worth supplementing the 'standard' instru-

ments for congestion management by other tools that can be realized through direct be-

tween GRTgaz and other infrastructure operators, such as TSO-to-TSO swaps or the re-

routing of flows. However, it is clear that the impact of such measures will be limited in most

cases and that they can only be provided on a best endeavors basis, which implies that they

can only be of a supplementary nature.

Last but not least, it is worth noting that GRTgaz may potentially encounter unexpected cas-

es of congestion which cannot be resolved by the proposed mechanisms or at excessive

costs only. It therefore appears prudent to provide for an additional back-up in the form of

entitling GRTgaz to directly intervene into the market in exceptional cases, i.e. in the form of

restrictions on certain nomination patterns. However, we emphasize that this should clearly

be regarded as a measure of last resort, similar to the current provisions for exceptional

actions where the network is outside normal operating conditions.

In the following sections, we provide further details and justification for each of the proposed

mechanisms, before commenting in section 6.2 on the steps we propose for implementation.

6.1.1 Core Instruments: Short- and Medium-Term Market Mechanisms

Short-term market mechanisms

In chapter 4 we have concluded that short-term market mechanisms, such as locational

trades, should be regarded as the preferred choice for managing congestion under normal

circumstances. Given that GRTgaz generally appears to have access to sufficient volumes

of flexibility at different locations, which can be used to relieve congestion as required, we

believe that GRTgaz should primarily rely on market mechanisms for congestion manage-

ment. Moreover, in order to limit costs and make sure that only those interventions really

required are carried out, we furthermore propose to use short-term, i.e. daily mechanisms.


As already pointed out above, we suggest considering the parallel application of two sepa-

rate products:

Locational trades; and

Capacity buy-back.

In general, locational trades should be considered as the standard solution as they are most

compatible with the general wholesale market, which suggests the biggest scope for compe-

tition. Nevertheless, as mentioned above, capacity buy-back measures may be a useful ad-

ditional instrument in those cases where the purpose is to prevent additional exit flows, even

before these have been nominated.

Locational trades involve a transaction for commodity between the TSO and shippers such

that they change the internal energy balance of the network. Since we assume that such

transactions shall not be mixed up with daily balancing, it is therefore necessary to compen-

sate at least the net balance of all locational trades. In principle, this could be achieved

through additional locational trades at other locations which are not critical for the type of

congestion in question. However, the particular structure of the congestion patterns implies

that the flows have to be constrained at a few specific locations only. Consequently, we as-

sume that the TSO would often be able to offset locational trades through counter trades at

an organized market, such as the spot market operated by Powernext. Relying on trades at

the virtual points principally offers access to a much larger group of shippers and can thus

be expected to result in more competitive offers for the TSO.

Alternatively, locational trades could also take the form of an obligation on shippers to adjust

their nominations. This option would not include any commodity transaction between the

TSO and shippers and would hence avoid the need for counter trades.

Irrespective of the detailed design of locational trades, it is finally clear that these would have

to be supplemented by temporary restrictions on re-nominations. More specifically, on each

day, shippers should not be allowed to make any re-nominations which cause a change of

flow opposite to the impact of a locational trade a given entry/exit point.

Medium-term market mechanism

Due to its potential scope, structural nature and costs, congestion from North to South re-

quires a robust mechanism to avoid unexpected problems in the short term. In the case of

Fos, this requirement conflicts with the fact that the nature of the LNG business requires

sufficient lead times, for instance if additional volumes of gas are required. As explained in

section 5.3, we therefore propose considering the application of monthly tenders. Similar to


the short-term mechanism mentioned above, these tenders should cover different locations

and products, in order to improve the scope for sufficient competition.

More specifically, we recommend the use of two at least different products43:

Firm flow commitments at Fos; and

Call options for capacity buy-back of exit capacity at TIGF.

The primary objectives of flow commitments at Fos would be to ensure the availability of

sufficient volumes of gas on a daily basis. In principle, this product could be combined with

further provisions, for instance in the form of a right (call option) for the TSO to call off differ-

ent volumes of gas on individual days. However, the increased complexity of a correspond-

ing product would not only make it more difficult to price, and hence potentially more expen-

sive. In addition, the corresponding flexibility may not be available to all shippers, or at least

not those without firm terminal bookings at Fos. In our view, preference should therefore be

given to the basic product offered for instance by Elengy, i.e. a flat injection of the cargo in

the form of a constant band over a period of 30 days. Amongst others, such a relatively sim-

ple design would also facilitate the evaluation of different offers, in an ideal case limiting the

criteria to the offered price only.

In contrast, we suggest using a different product at the border to TIGF, or potentially also

other exit points in the South. More specifically, we propose the use of call options which

allow – but do not require – the TSO to purchase back a certain volume of exit capacity on a

daily basis at a defined strike price.44 This product would provide sufficient certainty to the

TSO as it would effectively convert firm into interruptible capacity. At the same time, shippers

would still be able to use their exit capacity whenever there is sufficient capacity in the sys-

tem. Conversely, if capacity was bought back on a firm basis, the TSO might have to offer

these capacities back to the market in the absence of congestion, which would thus

represent an unnecessary intervention in the first place and additionally create another level

of complexity.

One potential disadvantage might be, however, that this product would not be perfectly com-

parable with the procurement of firm flow commitments at Fos, which may complicate an

efficient selection process by the TSO. Although this particular issue may deserve further

study, we believe that it may nevertheless be desirable to accept the corresponding inaccu-

racy in the selection process. Alternatively, flow commitments at Fos could comprise a pre-

defined strike price, despite the additional complexity and costs of a corresponding product.

43

In addition, monthly tenders could for instance also be open for participation by CCGTs.

44 The strike price might either be set by GRTgaz when announcing the tender, or be part of the individual offers

submitted by shippers.


In practice, we would envisage the following sequence of activities:

GRTgaz should define, after consultation with market participants, the needs of the

system in terms of the flexibility required to cope with the expected level of conges-

tion for the next month(s).

Secondly, GRTgaz should continuously monitor the market, in order to assess the

availability of flexibility, both in terms of daily capacity and the cumulative volume of

commodity available over a certain period, such as one or two months ahead.

The monthly auction process should be started whenever GRTgaz believes that the

need of flexibility exceeds the available supply.

The tender itself should be carried out in accordance with the framework and condi-

tions as outlined in section 5.3.4.

We emphasize that the proposed approach, based on an on-going risk assessment by

GRTgaz, may expose the TSO to substantial risk, in case its assessment has been either

too optimistic or too conservative. The tender process would therefore need to be supple-

mented by some form of incentives and sufficient safeguards to make sure that GRTgaz is

allowed to recover the costs of efficient purchases. However, this is a general requirement,

which equally applies to the use of short-term market mechanisms as explained above.

6.1.2 Potential Supporting Mechanisms

As mentioned above, the basic set of market mechanisms discussed in the previous section

should generally enable GRTgaz to successfully deal with physical congestion in a com-

bined market area, both with regards to potential peaks on individual days and in case of

structural congestion in the North-South direction. Nevertheless, the cost assessment in

chapter 5.6 has shown that the use of market mechanisms alone may result in very high

costs in some years. In addition, market mechanisms between GRTgaz and shippers may

not be able to fully exploit the flexibility inherent in the existing French gas infrastructure.

For these reasons, we recommend considering the application of the following two instru-

ments in support of the basic market mechanisms:

Conversion of firm exit capacity to TIGF to interruptible capacity; and

Enabling of locational storage swaps through a revision of storage bundles.

As already discussed in chapter 5, the conversion of firm capacity that has not been sold to

the market to interruptible capacity represents a potentially very effective and cost-efficient


instrument for mitigating congestion in the North-South direction. The corresponding ratio-

nale and issues have already been analyzed in section 5.3.2, such that we basically refer to

the corresponding part of the report for further information. Overall, this tool may therefore

provide for a very efficient tool for dealing with structural congestion.

In this context, we point out that the increased export potential to Spain (via TIGF) appears

to be one of the main drivers for structural congestion in the North-South direction in scena-

rio 1. At the same time, the Spanish market substantially depends on LNG imports, arguably

to a much larger degree than the gas market in (Southern) France. From the perspective of

French consumers, it thus appears more efficient to resolve physical congestion by reducing

exports to Spain (via TIGF) to the level of firm capacity, presumably in exchange for addi-

tional LNG imports to Spain, rather than trying to enable increased transit flows through

France at the expense of additional LNG imports at Fos, especially where the cost of the

latter are socialized to French consumers.

At the same time, we emphasize that it would also be necessary to consider the wider im-

pacts of this instrument for instance on the development of the gas market in the TIGF area

and, more widely, the level of integration between the GRTgaz and TIGF areas and, poten-

tially, even between the French and the Spanish gas markets. These issues, which are

beyond the scope of this study, should therefore be carefully studied before deciding on the

potential conversion of firm exit capacity to TIGF to interruptible capacity.

Secondly, the analysis in chapter 5 has shown that the modification of injection and/or with-

drawal patterns of underground storage represents a highly effective instrument for relieving

congestion from North to South. Simultaneously, the geographical location of different sto-

rages principally becomes meaningless for shippers in a combined market area. The intrinsic

value of different locations would thus be related to their impact on internal congestion within

the GRTgaz network only. Moreover, from the perspective of shippers, it might be preferen-

tial to be able to use a single type of storage, or a standardized set of product services that

differ by their product characteristics but not by location45.

Based on these considerations, a geographical revision of the current definition of different

storage groups might offer substantial benefits to shippers as well as to the infrastructures,

i.e. Storengy and GRTgaz. From the perspective of the TSO, this would allow the option of

agreeing on a jointly coordinated geographical distribution of the nominated injection or with-

drawal flows across the different sites. In theory, this should enable an optimal use of the

different physical storages for the purpose of congestion management. Furthermore, as long

corresponding changes stay within the (net) nominations submitted by shippers, this ap-

45

Due to the very different ratio of injection/withdrawal rates, we would expect that Saline would still have to be treated as a separate product.


proach would be virtually 'cost free', except for minor differences in compression costs on

different days. However, we note that a corresponding approach would imply that the cor-

responding geographical flexibility of underground storage can no longer be marketed by

shippers, i.e. that the corresponding income potential would be removed from the market.

In this context, it is also worth noting that Storengy may in any case have to rearrange its

storage products in a single market area. Consequently, the main requirement would thus be

to reinforce the existing level of coordination and cooperation between GRTgaz and Storen-

gy. In order to do so, a specific 'operating agreement'46 might be required between GRTgaz

and Storengy. The corresponding agreement, which could also become part of existing

agreements, would mainly have to specify the interaction between GRTgaz and Storengy in

the (daily) process for operational planning and dispatching, in order to ensure that the geo-

graphical diversity of underground storages can be used in the best possible way to manage

physical constraints in the network of GRTgaz.

When developing a corresponding set of operational and financial arrangements and decid-

ing on the future structure of storage products, a balance will obviously have to be struck

between the interest of GRTgaz in the highest flexibility possible, the commercial interest of

Storengy in maximizing the market value of its services, and finally the overall objective of

minimizing any detrimental impact on the wholesale gas market. As a general rule, it would

therefore appear logical that Storengy remained fully in charge of the definition of its com-

mercial offers to the market but that the interaction between GRTgaz and Storengy focused

on improved operational coordination within the context of the defined commercial products

and services.

As briefly mentioned above, the interaction between GRTgaz and Storengy might potentially

also involve the provision of a temporary lease and lending service for natural gas.47 Such a

product could potentially allow GRTgaz requesting Storengy to temporarily increase or de-

crease storage injections or withdrawals for a limited period of time, which would result in a

deviation between the (aggregate) nominations by shippers and realized physical flows. A

similar service could also be envisaged between GRTgaz and LNG terminal operators, in

this case in the form or a revised physical sent-out from the LNG terminals. In both cases,

the resulting deviations would obviously have to be compensated through an opposite varia-

tion at a later time.

As a consequence, the use of a corresponding product would be strictly limited by the need

of restoring the nominated storage inventory in due time. Nevertheless, this service might

46

Please note that the term 'operating agreement', here and in the following, is used in a general sense to de-scribe some form of agreement which governs some operational rules, procedures and information exchange between different infrastructure operators.

47 Please note that a corresponding service is used by some of the German TSOs for balancing purposes.


still be useful to deal with high levels of congestion on individual days. For instance during

cold spells in the winter, it might be possible to reduce congestion from South to North by

holding back part of the nominated injection into the grid for a few days and release the cor-

responding volumes once the situation in the network has normalized. In addition, this in-

strument may also help to reduce the exposure of GRTgaz to potential market power on the

side of shippers, i.e. by means of introducing some form of 'demand elasticity' for flexibility in

the daily market.

Obviously, a corresponding service would also require the development and implementation

of the necessary operating and/or commercial agreements between GRTgaz, on the one

side, and the operators of underground storage or LNG terminals, on the other side. Apart

from the operational arrangements, such agreements should also provide clear provisions

for the firmness of the corresponding service(s) and the potential remuneration.

6.1.3 Other Supplementary Measures

In the introduction to this chapter, we have argued that it may be worth supplementing the

'standard' instruments for congestion management by other tools, such as TSO-to-TSO

swaps or the re-routing of flows. Similar to the case of the storage-related instruments dis-

cussed in the previous section, these tools may require the development of new or the revi-

sion of existing 'operating agreements' between GRTgaz and other infrastructure operators.

Within France, it may be desirably to work on an improvement of the corresponding ar-

rangements with TIGF, in order to further improve the coordination and control of physical

flows between both networks. Amongst others, this should ideally include the use of possibil-

ities for relieving congestion by means of re-routing gas flows (compare section 4.2.11).

Similarly, GRTgaz may have to engage into corresponding discussions with foreign TSOs, in

order to enable and/or facilitate the re-routing of flows, or the use of TSO-to-TSO swaps

(compare section 4.2.10). In all these cases, some of the corresponding provisions may

already exist today. Similarly, it may often be possible to rely on existing contracts, such as

operating balancing agreements (OBA) with other TSOs. The main focus should therefore

not be on the development of new contracts, but the implementation and/or facilitation of the

underlying measures and principles.

Finally, we have repeatedly mentioned throughout this study that the primary focus of

GRTgaz should be on resolving congestion through the various (market-based) mechanisms

explained above. But although our simulations and analysis indicate that it should always be

possible to relieve congestion through corresponding measures, there is no absolute guar-

antee, in particular in case of lack of supply to the current market area GRTgaz Sud.


In principle, any resulting problems could potentially be regarded as unforeseen circums-

tances, or force majeure. In some cases, however, corresponding problems may also result

from a conscious decision not to hedge the network against every possible risk. From the

perspective of the TSO, it would therefore be desirable to clarify the corresponding definition

of 'normal operating conditions' in the applicable agreements for access to the network in a

way that the inability of GRTgaz to resolve congestion through corresponding measures

represents excursion outside ‘normal operating conditions’. Nevertheless, care would need

to be taken to ensure that the corresponding provisions are neither too wide to give the TSO

'carte blanche' for easy interventions when these may not be required, nor too narrowly de-

fined that they no longer cover all possible developments.

Another point in this context concerns the fact that any deviations from 'normal operating

conditions' can currently mainly be used to instruct a reduction of flows. With a view to a

potential deficit in the South of the GRTgaz network, it might also be desirable for the TSO to

be authorized to instruct forced deliveries to the system. However, since corresponding pro-

visions would result in tangible costs to shippers, this idea should be carefully scrutinized

before being introduced into the relevant contractual arrangements.

6.2 Proposed Steps towards Preparation of the Market

Merger

As a final part of this study, Table 26 provides a summary of different steps which we pro-

pose to take in order to prepare and implement the individual mechanisms outlined in this

chapter. In general, these steps should obviously only be taken once a general decision on

the use of the corresponding measures has been made. In several cases, we do however

believe that further discussions may be required before a final decision can be made. Con-

sequently, our initial proposal in several cases is to first carry out a detailed investigation

('feasibility study'), in order to develop and agree on the detailed outline of the corresponding

model, and then to take an informed decision afterwards.


Measure Required actions

Locational trades

Develop necessary product specifications, rules and contractual

agreements

Identify and agree with suitable market operator (Powernext?) for

establishment of required trading platform or, preferably, integra-

tion into existing organized market

Monthly tenders

Investigate feasibility of necessary modifications to current rules

for the use of LNG terminals at Fos

Consult with stakeholders on suitable products, timelines and ne-

cessary / acceptable restrictions

Develop necessary product specification, rules and contractual

agreements

Conversion of firm to


Discuss and decide on application of this option

Agree on remuneration for TIGF (if so desired)

Revision of storage

bundles and locational

storage swaps

Investigate possible / optimal scheme (Storengy, GRTgaz)

Check feasibility and prepare revision of product definitions, exist-

ing contracts and capacity reservations etc.

Discuss and agree on applicable possibilities, limitation, rules and

procedures between Storengy and GRTgaz

Re-routing of flows and

TSO-to-TSO swaps

Investigate potential improvements

Review / Develop operating agreements with other infrastructure

operators

Direct interventions (as

measure of last resort)

Review definition of ‘normal operating conditions’ and conse-

quences for network being operated outside these conditions

Other Ensure that GRTgaz has necessary procedures in place to proper-

ly analyze and forecast risk of future congestion

Table 26: Required steps towards implementation of recommended measures

In general, each of these activities is based on a number of general steps which can be

summarized as follows:

First, develop the detailed concept and principles of the mechanism;

Secondly, describe the roles and responsibilities of different stakeholders, interfaces

as well as the necessary processes and data exchanges;

Thirdly, develop all necessary rules, procedures and contractual agreements, and

amend the current regulatory framework where so required; before


Finally, specify, procure and implement any IT systems or other tools which may be

required to operate the corresponding mechanism.

In addition to the logical sequence of steps in each area, it is also important to provide for

overall consistency between the different measures and to ensure that efforts are initially

focused on those activities, which are most (time-) critical for successfully realizing the mar-

ket merger. Table 27 therefore presents a tentative roadmap for preparing and implementing

the necessary changes in each of the seven areas identified in Table 26 above. Please note

that the presentation of different steps in Table 27 focuses on the sequence of activities. In

contrast, the timing of activities in different areas relatively to each other is indicative only

and does not aim at a providing for an accurate representation of the length of different steps

in comparison to each other.

For the case that it is generally agreed to proceed with the market merger along the lines

proposed in this study, we would therefore propose the following:

In general, we believe that the first steps to be taken would be to consult on the re-

sults and recommendations of this study. Subject to potential modifications as a re-

sult of this consultation, a more detailed work plan should be set up thereafter to start

the work on the relevant proposals and instruments.

Once a detailed work plan has been agreed, work may immediately start on the im-

plementation of locational trades. We would envisage that it should be possible to

implement this instrument well in advance of the intended market merger. Besides

providing GRTgaz with additional instruments for managing the North-South link in

the current market48, an early start would make sure that this essential mechanism

can be extensively tested in real life before the market merger actually takes place.

Moreover, we also believe that it would be helpful to take first experiences into ac-

count when deciding on the potential need for flow commitments.

Similarly, we suggest starting at an early stage with the preparations for the introduc-

tion of flow commitments. Although the introduction of this mechanism itself may

not necessarily be very time consuming by itself, we believe that further efforts

should be spent to studying in more detail the feasibility, preconditions and implica-

tions for using flow commitments at Fos, in view of the specific nature of the LNG

business. Moreover, one has to take into account that this instrument may imply fur-

ther changes to be made to the contractual arrangements and/or operating rules at

the LNG terminal(s), which may take additional time. Conversely, we believe that the

48

As mentioned above new CCGTs in the South zone as well as the additional exit capacity to TIGF may princi-pally increase the frequency (and volume) of congestion between the North and South zone in the current market environment.


first flow commitments should only be contracted relatively shortly before the actual

start of the market merger.

With regards to the conversion of firm exit capacity to TIGF to interruptible ca-

pacity, there is no need for urgent action since the corresponding capacity has al-

ready been reserved for short-term allocation. Nevertheless, it appears useful to de-

cide on the potential use of this instrument early on in order to provide certainty to the

market. As such we propose that the wider impacts of this option should be studied

relatively soon, in order to take an informed decision and maintain sufficient time for

preparing alternative approaches in case this option is finally discarded.

With regards to the potential revision of storage products and the introduction of

locational storage swaps, we would basically envisage three different steps. First,

GRTgaz and the corresponding operators (Storengy, Elengy, STMC) should investi-

gate the feasibility and potential design of a corresponding scheme, before revising

the existing product definitions and drafting the necessary internal rules and agree-

ments in a second step. Thereafter, Storengy would probably have to start marketing

the new products well in advance of the market merger, whilst the actual use of loca-

tional swaps may potentially start at the time of the market merger.

Regarding the re-routing of flows and TSO-to-TSO swaps, we believe that these

instruments should not be directly linked to the time schedule for the market merger.

In contrast, potential options and improvements in this respect should be studied

and, where found to be positive, implemented even under the current market frame-

work. Ideally, the corresponding flexibility should thus become available well in ad-

vance of the market merger.

Conversely, we assume that the option of direct interventions as a measure of last

resort is not immediately time-critical. Nevertheless, the corresponding options and

requirements should be studied in due time, in order to ensure that the relevant con-

tracts and/or operational rules can be adjusted well in advance of the market merger.

In parallel, further work will finally be required on internal improvements within

GRTgaz as well as on potential changes to the regulatory framework. Amongst

others, the development of additional capabilities within GRTgaz may involve

changes to the internal organize and/or require training of internal staff. We therefore

believe that sufficient time should be allowed for these changes. Simultaneously

though, this activity should be regarded as an ongoing process which may have to be

adjusted in the light of the first experiences in the other areas, such as the introduc-

tion of locational trades, flow commitments or the use of locational storage swaps.


Step Measure

Locational trades

Monthly tenders Conversion of firm to inter-

ruptible capacity

Revision of storage bundles and locational storage swaps

Re-routing of flows and

TSO-to-TSO swaps


Other

1 Consultation on study results and recommendations

2 Set up detailed work plan for transition phase (2012 – 2015/2016)

3

Develop detailed design

Select market operator

Study feasibility and constraints

Decide on application

Study & assess wider impacts

Decide on application

Investigate poten-tial cooperation schemes (TSO + storage / LNG operators)

Study revised storage products (Storengy)

Investigate poten-tial improvements

Review / Develop operating agree-ments with other TSOs

Identify need for internal improve-ments (organiza-tion, IT etc.) (GRTgaz)

Discuss neces-sary changes to regulatory frame-work (GRTgaz, CRE)

4 Develop rules & procedures

Develop and agree on detailed products and timelines

Agree on distribu-tion of costs (if any) Study revised defi-

nition of 'normal operating condi-tions' and TSO authority

5

Design, procure & implement IT

Develop & con-clude framework agreements

Develop rules & procedures

Develop and publish initial sto-rage products (Storengy)

Develop coopera-tion rules and agreement (TSO + other operators)

6

Test phase

Develop & con-clude framework agreements

Use flexibility in daily operations

Incorporate new definitions and authorities into rules and agree-ments

Prepare internal organization for new tasks, incl. training of internal staff (GRTgaz)

Adjust regulatory framework where so required (GRTgaz)

7 Estimate initial needs (if any) Start marketing


Start marketing new storage products (Storengy) 8

Tender for initial flow commitments (if so required)

9 "Go live"

Table 27: Tentative roadmap for implementation of recommended measures


7. Appendices

7.1 Annex 1: Relevant Physical Constraints

See attached presentation:

"North & South zones merger. WP2 deliverable update. September 30th 2011"

7.2 Annex 2: Summary of Market-Based Assumptions

See attached presentation:

"Annex 2 - Main assumptions for market simulations"

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