1. business and industrial
2. energy
3. natural gas

PREPARATORY STUDY ON GENERAL REFORM
OF THE NATURAL GAS MARKET ACT
PREPARATORY STUDY ON GENERAL REFORM OF TEH NATURAL GAS
MARKET ACT
A Report to The Ministry of Employment and
the Economy
January 2015
PREPARATORY STUDY ON GENERAL REFORM OF THE NATURAL GAS MARKET ACT
Contact details
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Email
Telephone
John Williams
[email protected]
+44 1865 812262
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TABLE OF CONTENTS
1.
INTRODUCTION
1
2.
THE BUILDING BLOCKS OF ESTABLISHING A COMPETITIVE MARKET
IN FINLAND
3
2.1
Benefits of competitive markets
3
2.2
Building blocks of competitive gas markets
3
3.
4.
5.
6.
ENHANCING THE PROSPECTS OF MARKET FUNCTION IN FINLAND
5
3.1
Enhance National Legislation
5
3.2
Develop the incumbent as an enabler for market liberalisation
6
3.3
Increase supply diversity
7
3.4
Enhancing market size
8
3.5
Delivering market opening
8
3.6
Market Arrangements
8
OPTIONS FOR FUTURE MARKET DEVELOPMENT
11
4.1
Option 1: National Market
11
4.2
Option 2: interconnected National Markets
17
4.3
Option 3: East Baltic Market Zone model
20
EVALUATION OF THE POTENTIAL MARKET MODELS
23
5.1
Potential to establish a functioning wholesale market
23
5.2
Security of Supply
23
5.3
Complexity of arrangements
24
5.4
Cost
25
CONCLUSIONS AND RECOMMENDATIONS
27
ANNEX A – ADDITIONAL INFORMATION
29
A.1
A.2
Ownership Unbundling Options
LNG Operational Models
29
31
A.3
Entry-Exit Principles
33
A.4
A.5
European Trading Hubs
Market Arrangements requirements under EU Network Codes
35
36
A.6
Market Opening Examples
45
QUALITY AND DOCUMENT CONTROL
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1.
INTRODUCTION
Finland has isolated market status because it is not directly connected to the
interconnected system of any other Member State and it has only one main external gas
supplier. Finland therefore has a derogation from parts of the Third Energy Package. It is
currently exempt from full market opening, the unbundling of the transmission and supply
elements of the incumbent Gasum Oy and from implementation of the market rules aimed
to deliver third-party access and a functioning wholesale market.
However a regional LNG regasification terminal may be constructed in Finland thus
allowing access to the global LNG market and if this project is realised and there is
enough gas purchased through the terminal then our understanding is that the exemption
in Finland will end.
The proposed Balticconnector would allow direct access to the Estonian gas market and
the connected Latvian and Lithuanian gas markets. If the Baltic system (comprising
Finland, Estonia, Latvia and Lithuania) is physically connected to a non-Baltic Member
State then compliance with the Third Energy Package’s unbundling requirements, market
opening requirements and European Network Codes would be mandatory. This could be
achieved if the Gas Interconnection Poland-Lithuania (GIPL) is built.
In light of these potential developments, the Natural Gas Market Committee is tasked to
propose amendments to the Natural Gas Market Act (NGMA). This study has been
commissioned in order that the Natural Gas Market Committee may understand the
building blocks that are necessary to deliver Third Energy Package compliance and a
competitive gas market, understand some relevant international experience and the
options for a regional market in the eastern Baltic States.
The project has been delivered over two workshops and this report contains the summary
of the discussions and Pöyry’s recommendations. Some of the relevant content of the
workshops is contained within an Annex to this report and includes:

options for ownership unbundling in Annex A.1;

alternative models of commercial LNG terminal activities in Annex A.2;

an overview of entry-exit transportation models in Annex A.3;

the development of European gas hubs in Annex A.4;

an overview of the requirements of the EU Network Codes and Guidelines in Annex
A.5; and

a comparison of other markets including Sweden, Republic of Ireland and the Baltic
states in Annex A.6.
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2.
THE BUILDING BLOCKS OF ESTABLISHING A
COMPETITIVE MARKET IN FINLAND
The Third Energy Package aims to deliver a properly functioning integrated energy market
via competition in both wholesale and retail gas markets.
2.1
Benefits of competitive markets
The benefits of competitive gas markets include:

more efficient wholesale gas prices linked to supply/demand fundamentals rather
than to oil-indexed long-term contracts;

shipper and end user access to efficient and functioning wholesale gas markets;

improved diversity and security of supply as alternative supply sources are developed
and new entrants are encouraged to the market; and

competition in the end user market which will encourage increased end user choice,
a higher quality of service, better consumer protection and access to innovative
products that are tailored to specific end user needs.
2.2
Building blocks of competitive gas markets
A series of essential building blocks are necessary to deliver a competitive and functioning
gas market.

A fit-for-purpose Legislative and regulatory framework that establishes the
requirement to:
 open the gas supply market comprising all gas eligible customers and establish a
clear market opening timetable;
 unbundle the activities of gas transmission and gas supply through the legal and
functional separation of the ‘natural monopoly’ of transportation from supply and
by ensuring that a level playing field is created for new entrants;
 establish the duties and enforcement powers of an independent energy regulator
in a fully competitive market;
 establish the licencing framework for relevant market roles;
 define the access and balancing arrangements associated with the transmission
and distribution system network; and
 establish the principles and mechanisms for determining tariffs for access to the
transportation network.

Access to more than one supply source providing secure and diverse supply and
gas-on-gas competition.

Non-discriminatory and transparent Third-party access rules to the transmission
system and to LNG facilities and storage (where available).

Create the conditions to encourage a functioning wholesale market with multiple
buyers and sellers of gas that encourages price-discovery and facilitates new
entrants.
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3.
ENHANCING THE PROSPECTS OF MARKET FUNCTION
IN FINLAND
In order to enhance the prospects of developing a functioning market in Finland the
following are required:

enhanced national legislation;

supply diversity;

unbundling of the incumbent;

enhancing market size;

delivering market opening; and

introducing revised market arrangements.
3.1
Enhance National Legislation
The current NGMA does not require the establishment of a competitive gas market that is
compliant with EU requirements as set out in the Third Energy Package. This has been
recognised and the Ministry of Employment and the Economy is actively engaged in
addressing the amendments that will be required to national legislation in Finland.
Currently the NGMA provides for the unbundling of accounts of Gasum’s transportation
and supply activities but limited progress towards market opening has taken place.
Secondary gas trading occurs between end users and retailers that consume in excess of
5mcm/yr of gas, have telemetry installed and where the gas is sourced from the sole
importation route. It is not currently possible for end users below this threshold to
participate in a secondary market or to choose their supplier. Third-party access
arrangements are, however available for gas sourced from renewable sources, although
the volumes of gas remain low at present.
Given the small size of Finnish and Baltic regional gas demand it is essential that a
proportionate framework is established to manage the new gas environment.
International experience should inform Finnish decisions.
Relatively larger markets have used licensing frameworks that involve, for example,
shippers, suppliers, traders and market operators. Such complicated structures and
splitting of roles may be inefficient in Finland and may not be required in order to deliver
benefits to end users. The revisions to the NGMA should therefore provide an enabling
framework so that the Energy Authority has adequate independent power and delegated
authority so that, wherever possible, a Finnish Network Code1 (FNC) can address the
necessary rules, processes and obligations to facilitate a properly functioning market.
The NGMA must therefore define the governance process for the establishment and
evolution of the FNC as well as specify its general scope, aims and objectives. For
example the FNC will need to define the general rights and obligations framework that will
apply to all counterparties including TSOs, DSOs and shippers2.
1
National Network Codes are the normal route whereby the market rules are set out in a
contractual document that the transmission system operator and the market participants are
required to sign. This will set out, as a minimum, the main commercial framework.
2
The term ‘Shippers’ is used generically to include market participant roles that would include
shippers, suppliers and traders in more developed regimes.
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However, whilst an appropriate and robust legislative framework is necessary it is not, by
itself, sufficient to ensure that a competitive market develops.
3.2
Develop the incumbent as an enabler for market liberalisation
Gasum Oy is currently a vertically integrated company consisting of four business units:

transmission;

energy supply;

energy services; and

LNG.
It is outside the scope of this study to recommend how the Gasum Oy business should be
unbundled other than to recognise that there are three options open for consideration:

Full Ownership Unbundling (FOU);

Independent System Operation (ISO); and

Independent Transmission Operation (ITO).
These options are described in more detail an Annex A.1.
As a minimum, the transmission business unit should be unbundled from the energy
business. This could create two separate companies which are referred to, for the sake of
convenience, as Gasum TSO, that consists of the transmission system operation and
Gasum Supply which consists of the energy supply and service businesses. The LNG
business (including the potential new regasification terminal) could continue as a separate
business or fall within either the transmission or supply businesses.
The unbundled TSO has a critical and unique enabling role to facilitate the competitive
market. There is merit therefore that the TSO is unbundled as soon as reasonably
practical on the path to liberalisation of the market. Unbundling before the development of
the FNC, full market opening and the introduction of new processes and data exchange
would help ensure its impartiality and suitability for its facilitator role towards delivering a
properly functioning market. The TSO must be appropriately incentivised to operate its
gas transmission system in accordance, wherever possible, with the commercial
aspirations of shippers. It may also have a significant administrative function developing
and operating IT systems and data communication to support proper market function.
Experience in other countries would suggest that early and effective TSO unbundling
accelerates the process of market development.
The establishment of a functioning market will have impacts for the Finnish gas chain.
The liberalisation process will generate short term costs that need to be considered
against the longer term benefits of a liberalised market. However in the short term the
distribution of these costs and impacts upon the incumbent and end-consumers will need
careful consideration.
The European model requires full retail market opening. However a large proportion of
Finnish end-users (around 30,000) have small unmetered cooking demands. The
aggregate consumption of these end users represents only around one per cent of Finnish
gas demand. Proportionate approaches will therefore be necessary to ensure that market
opening is delivered in an economic and efficient manner and delivers the greatest
benefits to the vast majority of the gas demand.
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3.3
Increase supply diversity
Currently the market is dependent on a single supply source from Russia with importation
being carried out solely by Gasum Oy. Without an alternative supply source it is unlikely
that a sustainable competitive and fully-functioning market can be established. Gas-ongas competition is required in order that multiple sellers of gas are at least possible.
Finland has no significant indigenous natural gas resources so new gas sources can only
come from physical sources outside of Europe or from gas available within the EU
Transmission grid3.
New pipelines to bring new supplies into Finland are unlikely given Finland’s small market
size and the cost of pipelines even for the closest Norwegian gas supplies.
LNG may be the best option to provide a new gas source provided sufficient financial
support (perhaps from the European Commission and/or the Finnish Government) is
available to secure the necessary investment in a regasification facility. The commercial
model for the LNG facility would need to be determined. Annex A.2 provides further detail
about the structures that might be considered. It is, however, the potential impact of new
gas sources on both wholesale gas pricing and retail competition that is critical. For
example it is not clear that LNG gas supplies will significantly undercut the price
associated with Russian gas imports. However the terminal would assist negotiations with
Gazprom Export and the option to take LNG may lead to better importation prices than
might otherwise be achieved. Furthermore, the availability of alternative non-Russian
supplies may assist new players to secure gas for supply into the end user market once
further market opening has taken place.
The Balticonnector, as an intra-Europe pipeline, is expected to facilitate a north-south
physical flow direction i.e. from Finland to Estonia. However, it could enhance the gas
sourcing options for gas in Finland if sufficient capacity exists to enable a south-north flow
direction. The effectiveness of this interconnection will depend upon whether it can
provide access for other non-Russian supplies perhaps from Lithuanian LNG or from
further afield, for example gas from the Polish market via GIPL (including from Polish LNG
importation or from gas sourced south or west of Poland). Gas pricing at hubs,
transportation pricing and transmission capacity availability will determine whether such
benefits may arise in Finland.
Whilst a voluntary Release Gas4 programme may provide a temporary mechanism to
encourage new entrants until an alternative supply source is in existence, without an
alternative source to the Gazprom Export long-term contract, competition is unlikely to
develop or to be sustainable. In the absence of gas-on-gas competition in respect of
imports into Finland further liberalisation will generate costs but few benefits to Finnish
end consumers.
3
According to the Government Energy Strategy, Replacement of around 10 per cent of
natural gas with synthetic natural gas made from domestic wood by 2025 might be
achievable.
4
Gas Release programmes involve an incumbent gas company ‘releasing’ a volume of its
contracted gas to new entrants. For example this was used in the GB market to speed-up
market entry whilst awaiting increased competitive supply of gas. Gas Release has
subsequently been used in other developing markets (e.g. Italy) to accelerate progress.
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3.4
Enhancing market size
The national market of Finland is relatively small by international standards and is
currently in the region of 3.5bcm/yr. There is some potential for market growth but this is
dependent on the commercial attractiveness of gas relative to alternative fuels and will
require extension of transmission and distribution infrastructure to extend the mains gas
supply area to the Finnish west coast. Additionally there is some potential for small scale
LNG to meet bunker fuel demand and to supply off-grid customers.
The potential market size could be expanded through connection with the other eastern
Baltic states if sufficient interconnection capacity exists and can be accessed by market
participants.
The size of the gas market may provide a constraint on market development. It may not
be of sufficient size to attract many new entrants once the correct conditions exist as the
costs of entry may be higher than the perceived potential rewards. A light
regulatory/licencing regime might therefore limit barriers to entry but it is unlikely, for
example, that Finland will ever be able to satisfy the extensive criteria for a properly
functioning gas market as will be published by ACER in its revised Gas Target Model to
be published 16 January 2015.
3.5
Delivering market opening
Whilst end users and retailers that consume in excess of 5mcm/yr are able to separately
purchase transmission services and have access to a limited gas exchange facility, the
market is not fully open for retail market competition. Delivery of full market opening will
be mandatory if Finland’s Third Energy Package derogation was to end and the Baltic’s
energy island status was to change.
A timetable to achieve full market opening, which may be gradual depending on end user
size will be important. The obligation to fully open the market and the timetable may be
expected to be included in the NGMA.
In addition to the timetable, new business processes will need to be enacted to enable full
retail competition for Finnish end users. These business processes will need to
accommodate customer switching procedures and all the consequences of this including
capacity (e.g. reservation and payment obligations) and balancing (e.g. portfolio balancing
arrangements and associated settlement processes). Proportionate approaches will be
necessary to ensure only efficient costs are incurred. For instance it may not be
economic to develop procedures so that all non-metered demand to be opened to
competition unless a meter installation programme is carried out. The costs of this are
almost certain to outweigh the benefits.
3.6
Market Arrangements
New third-party access arrangements will be needed to manage the transition from the
vertically integrated monopoly transmission and supply company to a fully open and
competitive market. The arrangements will need to apply to the wholesale market and
also to enable a fully open market at the retail level.
Currently, a limited secondary market for gas exists. It allows larger end users to trade
gas between themselves on a trading platform. The incentives are driven by the gas
sales tariffs of the incumbent monopoly. The fact that this trading platform exists and that
end users and a Gasum Oy subsidiary, Kaasuporssi are actively engaged is a promising
indicator that multiple buyers of gas could emerge given the correct market arrangements.
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Market arrangements must be transparent, non-discriminatory, and should facilitate the
development of a fully functioning wholesale market. There is a requirement to develop
and implement a transportation regime based on entry-exit principles as set out in more
detail in Annex A.3.
Whilst the aspiration of the original Gas Target Model5 was to deliver fully functioning
wholesales markets in all entry-exit zones within Europe it is becoming apparent that this
is a very ambitious aspiration that may not be delivered everywhere. Whilst Virtual
Trading Points and Gas Exchanges are widespread across Europe few are liquid
particularly along the trading curve 2-3 years forward (see Annex A.4).
The challenge will be to ensure proportionate arrangements that enable market
functioning but without introducing substantial costs that would be difficult to recover over
the relatively small gas consumer base in Finland.
5
CEER Vision for a European Gas Target Model. Conclusions Paper, 1 December 2011.
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4.
OPTIONS FOR FUTURE MARKET DEVELOPMENT
In the consideration of the options to develop the Finnish gas market, three alternatives
have been identified. These are referred to as: a National Market model (NM model), an
Interconnected National Market model (INM model) and East Baltic Market Zone model
(EBMZ model). In each of these models it is assumed that the regional LNG terminal is
located in Finland following the securing of sufficient funding from the EU or other sources
to allow the construction of the facility. In the INM model and the EBMZ model it is
assumed sufficient financing is also available to support the construction of the
Balticonnector. In each of the models considered it has been assumed that the
derogation and exemptions currently in place will fall away requiring implementation of the
Third Energy Package in full. The alternative market models are shown in Figure 1.
Figure 1 – market model alternatives
This section develops each model and outlines some of the critical elements that would
need to be put in place to implement each of the models. Many of these elements are
absolute requirements of the Third Energy Package and so are common to all three
models.
4.1
Option 1: National Market
Key requirements involve the unbundling of Gasum Oy, opening of the market to
competition, and third-party access for both the transmission system (based on entry-exit
principles) and the LNG facility (assuming that a third-party access exemption has not
been secured).
It is assumed these requirements will be set out in, or at least enabled by, the revised
NGMA. It is expected that the revised NGMA will place responsibilities on the TSO and
the Energy Authority to develop, implement, monitor and evolve the market rules including
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a specification of the high level content and governance of any necessary licences and
codes. For example a FNC would be a requirement that might be a derivative of the
current arrangements but would be compatible with EU law. The FNC would be a multilateral contract between all shippers and the TSO. Depending on the approach used it
may also be essential for the DSOs to be party to the arrangements.
Our assumption is that the normally licenced activities seen in many other more
developed gas markets including shipper, supplier, trader, LNG facility operator, DSO, will
be identified in the revised NGMA. Careful consideration must be given to the NGMA
specification, the role and responsibilities of the Energy Authority and the scope of the
FNC and any other additional contractual arrangements (e.g. LNG facility access
arrangements and their governance) to ensure proportionate frameworks in such a small
market. For instance, shipper obligations could be included in the FNC, rather than in a
specific licence. Compliance of shippers with the FNC could be monitored by the Energy
Authority, which would be empowered with enforcement actions if non-compliance were
evident.
Thus the requirement for the FNC to be developed and implemented by the TSO should
be included in the revised NGMA. The FNC would define the entry-exit regime detailing
relevant user switching, capacity, balancing and tariff arrangements. These arrangements
will need to be compliant with European legislation so the general rules about capacity
booking and management will apply. Furthermore the EU Balancing Network Code and
EU Tariff Network Code arrangements (when they are agreed) will require
implementation. However there will be no requirement to implement the CAM, CMP or
Interoperability Network Codes as no Interconnection Point will exist.
Annex A.5 further elaborates the current and expected requirements arising from the EU
Network Codes and Guidelines that comprise the suite of rules under the umbrella of
Regulation (EU) 715/2009.
4.1.1
Planning the transition to the National Market (NM)
In this section an initial analysis of the following is provided:

gas supply sourcing;

legislative and licencing framework;

market opening;

commercial framework rules (FNC);
 customer switching;
 capacity;
 nomination and allocation rules;
 balancing; and
 tariffs.
4.1.2
Gas supply sourcing
The LNG regasification facility could enable gas-on-gas competition to develop in Finland.
The facility would give access to alternative sources of gas potentially from the LNG spot
market if the commercial access arrangements facilitate this. Thus market developments
will depend upon two critical elements: the access arrangements to the facility including
for example long term capacity rights and shorter term access (including Use-it-or-lose-it
(UIOLI) services) and the likely price of gas delivered at the facility. Whilst Finnish policy
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decision making may heavily influence the former, the latter will be determined by the
global interactions that influence LNG prices.
The lead-time for the new facility, assuming that adequate finance can be secured, will be
several years.
To speed developments towards wholesale market functioning Gasum Oy might offer
wholesale gas to new entrants under a voluntary Gas Release programme. Under this
Gasum Oy would ‘release’ it’s contracted gas to new entrants which would then enable
them to supply end users.
In order that wholesale market development is encouraged, the delivery point of the gas
under the Gas Release programme could be the Virtual Trading Point to focus liquidity.
The pricing of and the gas flexibility terms contained in such release contracts will be
critical. Purchasers of the release contract may need sufficient flexibility to manage their
exposures and the gas price will need to be set to provide a margin opportunity for new
entrants. Careful consideration will therefore need to be given to the costs, risks and
possible compensation afforded to the incumbent.
4.1.3
Legislative and Licencing framework
The NGMA will need to define the relevant activities and associated governance of
licencing and market participant roles. The following roles are expected to be recognised
and for the Energy Authority to have monitoring and enforcement powers to ensure that all
actors satisfy the legal requirements which will be defined in the NGMA and the FNC:

transmission system operation to include requirements such as:
 separation from supply activities;
 economic and efficient operation and maintenance of the transmission system;
 economic and efficient balancing of the transmission system;
 implementation of the FNC containing transparent and non-discriminatory
market rules;
 development and publication of transparent and non-discriminatory transmission
tariffs and methodologies;
 facilitation of customer switching;
 information provision;
 management of gas quality;
 emergency procedures;

LNG operation to include requirements such as:
 enabling third-party access to regasification capacity;
 offer UIOLI services;
 publish tariffs for use of the regasification facility;

shipper to include requirements such as:
 compliance with the FNC;
 information provision;
 emergency procedures;

supplier (may be combined with the shipper role) to include requirements such as:
 customer obligations;
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

customer switching; and
Distribution system operation to include requirements such as:
 development and publication of transparent and non-discriminatory distribution
tariffs and methodologies;
 facilitation of customer switching;
 balancing provisions (if not covered in the FNC);
 information provision; and
 emergency procedures.
4.1.4
Market opening
The NGMA needs to include obligations to facilitate full market opening. The obligations
should include a market opening timetable and obligations for the Energy Authority to
ensure that all rules (to be placed in the FNC) and business process are enacted by TSO,
DSO and other parties.
Where a single party has a dominant supply position it may be required that it publish
regulated supply tariffs until its market share has reduced to a specific percentage of the
total market. This would be monitored by the Energy Authority.
It will also be necessary to identify a Supplier of Last Resort (SoLR) that will be the party
responsible for supplying gas to customers in the event of a supplier failure due to
insolvency or withdrawal of the outgoing shipper or supplier.
4.1.5
Finnish Network Code (FNC)
For the purposes of this report it is assumed that all further market enabling measures
(beyond those to be reflected in the primary legislation including the NGMA) associated
with the TSO related activity will be captured within the FNC and approved by the Energy
Authority. The FNC would need to embrace relevant activities and obligations of other
players (e.g. Distribution System Operators, Trading/Balancing Platform Operators) where
appropriate. The FNC will also need to contain robust modification procedures in order
that changes may be proposed and considered ensuring adequate consultation and a
consistent decision making process.
Whilst a full specification of the code required is out of scope of this project6 the following
are noteworthy:

End user switching - to define necessary business processes to enable end user
switching. This will need to cover responsibilities for registration, securing meter
readings and reconciliation of transportation charging (should any form of flow-based
commodity charge be used in tariffs) and some elements of post-gas balancing close
out reconciliation quantities.

Nomination and allocation rules - the TSO in its system balancer role will require
information about shippers’ intended physical flows on the system (nominations).
Additionally shippers’ transportation and gas balancing exposure will be determined
by allocations (their actual gas flows used for settlement purposes). Rules will need
to be defined in the code to define the relevant processes and obligations. For
example, rules relating to meter readings, portfolio information, and daily portfolio
6
Annex A.5 provides more background to the binding gas market rules requirements.
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allocation information will all be necessary to ensure proper gas accounting and
market functioning.

Forecasting and Reconciliation – for end users that do not have daily read meters
there will be a requirement for the TSO to produce a non-daily-meter (NDM) forecast
demand and to issue this to the relevant parties. This enables the shippers to deliver
sufficient gas to the transmission system to meet demand. Once NDM meters are
read, then a reconciliation process is required to correct for any variances in gas
balances and transportation charges that are due to the inevitable differences
between forecasts and actual consumption.

Capacity - in the absence of an interconnection point (IP) with an adjacent European
country the Capacity Allocation Mechanisms (CAM) code, Congestion Management
Procedures (CMP) guidelines will not be necessary. However the Third Energy
Package contains other more general rules (including explicit decoupled long and
short-term entry and exit capacity) that will need to be reflected in the FNC.

Balancing - balancing is at the heart of developing a properly functioning wholesale
and retail gas market and is the key challenge that must be addressed in the FNC. A
transitional plan will be necessary and the Natural Gas Market Committee should
note that the EU Balancing Network Code envisages a 5 year transition to enable the
market to develop. Furthermore the balancing code recognises that a market cannot
be forced; enabling rules can be developed but the environment has to be sufficiently
attractive for a properly functioning market to develop.
The transitional plan for balancing is outside of the scope of this report but a number
of critical elements will need to be addressed including:
 encouraging market players to offer flexibility from the gas supply side;
 balancing tools available to the TSO;
 creating the environment to encourage short-term gas trading, including the
implementation of the VTP (to provide the focus for liquidity and gas price
discovery), and the introduction of balancing or trading platforms;
 establishing the necessary information flows to support the TSO’s system
management activity and the shippers’ individual balancing responsibility;
 developing the incentive framework that will encourage shippers to self-balance
(via the cash-out regime); and
 defining the balancing settlement and financial neutrality arrangements for the
TSO (in its market facilitation role).

Tariffs - whilst the European Tariff Network Code is not yet finalised it should be
expected to have implications that will need to be addressed within the FNC.

IT systems and communications infrastructure - IT systems and data exchange
will be an essential element of the market. The provision of these services,
responsibilities and obligations will need to be defined in the FNC. To ensure efficient
outcomes the IT systems and processes will need to be proportionate having regard
to the small market size. It is likely that the core system delivery and management
should be the responsibility of the TSO in its market facilitation role.
Annex A.5 provides further detail about the European legislative requirements arising from
the EU Network Codes and Guidelines.
Figure 2 shows how the NM Model may look. This is based on the following expectations
of market functioning:
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
Gasum Supply and potentially new entrant shippers will purchase Entry Capacity at
the Imatra Entry Point via rules set out in the FNC at tariffs that are approved by the
Energy Authority.

Gasum Supply is likely to remain a major importer of gas at Imatra but may choose,
on a voluntary basis, to ‘release’ gas to shippers at the VTP via a Gas Release
programme. Gasum Supply could also ensure that the TSO has access to balancing
gas resources to ensure that sufficient bids and offers are available to the TSO at all
times.

The commercial framework should allow new entrant shippers to purchase gas from
Russia at the Imatra Entry Point and to subsequently trade gas at the VTP.

The commercial arrangements covering Entry and Exit Capacity sales and Balancing
and Information Provision are contained within the FNC.

New entrant Shippers access the market through purchasing gas and Entry Capacity
at the LNG Entry Point. New entrant Shippers can also buy and sell gas at the VTP.
The commercial arrangements at the VTP will also be contained within the Network
Code.

In order that Gasum TSO can access balancing gas services, it buys/sells balancing
gas at the VTP and transacts with shippers via a balancing/trading platform.

The existing secondary market platform is replaced with a trading platform at the VTP
thus focussing liquidity at this point. Standardised products should be developed that
meet the requirements of shippers and the TSO (in its residual balancing role).

Shippers will buy Exit Capacity at Transmission Connected Exit Points and at the
Transmission Exit Points to the Distribution Networks.

All shippers, including Gasum Supply are able to buy gas at the VTP and trade with
each other and Gasum TSO (in its system balancing role).

Gasum Supply and new entrant shippers will be able to buy gas from the VTP and
deliver gas to end consumers and Distribution Zones where they have purchased Exit
Capacity from Gasum TSO.

Some of the large End Consumers (>5mcm/day) may become shippers and buy gas
at the VTP and Exit Capacity from Gasum TSO for their own use;

Shippers move gas to the Distribution Zones and pass title of gas to the suppliers at
the consumer meter. Shippers will be liable for distribution system transportation
charges.

Suppliers (or shippers if the roles are combined) are responsible for the marketing,
billing, metering (potentially if this is where the responsibility lies) and customer
service at the retail level.
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Figure 2 – National Market Model
4.2
Option 2: interconnected National Markets
The INM model will connect the gas markets of Finland, Estonia, Latvia and Lithuania
through the establishment and functioning of cross-border Interconnection Points (IPs).
Shippers will be able to access each of the gas markets by acquiring capacity at the IPs
and then making the appropriate gas nominations. This would allow Gasum Supply to
trade in the other East Baltic gas markets and would enable Estonian, Latvian and
Lithuanian supply companies to move gas into Finland and access the Finnish gas
market.
The Balticonnector will link Finland and Estonia requiring the establishment of an IP.
Estonia and Latvia will share an IP as will Latvia and Lithuania. Harmonised
arrangements at the IPs should allow efficient cross-border gas movement where there is
sufficient bi-directional cross-border capacity. Where bi-directional flows are not possible
virtual reverse flow rules will be required to ensure the market is able to optimise gas
flows.
This model will require all the features of the National Market model to be in place.
For the purpose of this report it is assumed that similar national arrangements including
unbundling, third-party access and VTPs are, or will be, in place in the other East Baltic
states. Some co-ordination and alignment of national systems might also allow for better
and easier wholesale and retail competition.
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In order for the INM model to function, the CAM, CMP and Interoperability arrangements
contained within the EU Network Codes shall be implemented at each of the IPs7. Gasum
TSO will therefore be required to bundle capacity at the IP with Võrguteenus, the Estonian
TSO. Gasum TSO and Võrguteenus will be required to define bi-directional capacity
quantities and develop standard bundled capacity products to be offered in annual,
quarterly, monthly, daily and within-day auctions.
4.2.1
Planning the transition to Interconnected National Market (INM)
All of the steps required for the National Market (NM) implementation will be required for
the INM model.
If the Balticonnector’s availability follows the Finnish LNG regasification plant then the NM
might be regarded as an intermediate step. Otherwise if the Balticonnector precedes the
Finnish LNG regasification plant then the requirements of the NM model will have to be
dealt with, together with CAM, CMP and Interoperability requirements when the INM
model is implemented.

Capacity Allocation Mechanism (CAM) Code - Adjacent TSOs will be required to
co-operate to maximise the release of technical capacity in both directions. The
products will be sold as bundled capacity (i.e. capacity to get from one VTP to the
adjacent VTP) using standardised products (annual, quarterly, monthly and daily).
Capacity release will be via auctions (with a minimum reserve price) so that, in the
event of scarcity, those network users valuing it the highest at the point scarcity is
realised will secure the capacity allocation. The detailed processes and timelines for
capacity release are defined in CAM and the relevant TSOs will be required to use a
single booking platform.
Whilst many European TSOs are using Prisma as the platform other options exist and
should be considered to ensure an economical and fit for purpose solution is
identified.

Congestion Management Principles (CMP) Guidelines - the Commission’s
Guidelines are annexed to Regulation (EC) 715/2009 and therefore directly applicable
(once the Finnish Third Energy Package derogation lapses)8. TSOs are obliged to
implement rules designed to mitigate or eliminate the risks of contractual congestion.
The rules require business processes to facilitate:
 over-selling and buy-back of capacity;
firm day ahead UIOLI restrictions;
 surrender of capacity by shippers; and
 long-term UIOLI mechanisms.
Figure 3 shows how the INM Model may look. This is similar to the NM Model shown in
Figure 2 with the addition of the Balticonnector IP that allows for an additional exit route
from the VTP and an entry route (in reverse flow mode) to the VTP. In addition to the
market features of the NM Model this will require:
7
Without an East Baltic pipeline connection to a non-Baltic Member State this is, strictly
speaking, not necessary although for the purposes of this report it is considered it unlikely
that any non-EU compliant access rules at IPs would be considered in the East Baltics.
8
Regulations are automatically applicable in Member State’s once they enter into force.
Directives require implementation into national legislation in each Member State.
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
The development and implementation of CAM, CMP and Interoperability
arrangements at the IP as required by the EU Network Codes.

The NGMA may need to specify that the Finnish TSO shall be required to cooperate
with the adjacent Estonian TSO to implement the arrangements required at the IP.

It is expected that the Balticonnector will, under normal market conditions, flow in
forward flow mode i.e. from Finland to Estonia. However, reverse flow arrangements
will also be put in place which should allow for physical reverse flow (from Estonia to
Finland) if this flow direction can be accommodated. As a minimum, virtual reverse
flow arrangements will need to be put in place whereby virtual flows from Estonia to
Finland may be offset by physical forward flows from Finland to Estonia.

Additional IT systems9 are expected to be required in order to facilitate the
implementation of the IP, offer capacity for sale and allow data exchange between the
TSOs and between TSOs and shippers at the IP.
Figure 3 – Integrated National Market Model
It is possible that an additional IP, at the boundary of the Baltic interconnected states, may
be created between Lithuania and Poland assuming that the GIPL project reaches
implementation. This would allow access to the Polish gas market and additional sources
of gas. This potential development could allow the Finnish gas market to access the
additional liquidity that may exist at a Polish gas exchange assuming that sufficient
9
This goes beyond the choice of a capacity platform whether it is Prisma or an alternative.
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infrastructure projects are developed to facilitate a south to north flow direction from
Lithuania to Finland.
4.3
Option 3: East Baltic Market Zone model
In the EBMZ model, a single regional entry-exit zone is considered. Thus, a common set
of market rules would be established for the whole region to include Finland, Estonia,
Latvia and Lithuania.
The single entry-exit zone implies a single balancing zone and therefore a single VTP for
the region. There will be no requirement for the establishment of IPs between Finland or
between any of the Baltic states. From an external perspective; no cross-border capacity
would be visible to the market and gas flows would be nominated by shippers at any entry
points to the zone and at any exit points from the zone. This ‘free-flow’ of gas provides a
flexible model for shippers but requires complex arrangements to manage the physical
flow of gas across the zone and may require the frequent use of inter-country adjustments
or recourse to locational balancing services.
In order to facilitate single system operation greater co-operation would be required at
numerous levels and in many different forms. For example, a new set of contracts
between the TSOs could be established, a joint venture established for the co-ordinated
operation or in extremis all of the (unbundled) TSOs could merge into a cross-border
super-TSO. Whichever model is chosen the co-operation (whether via many contracts, a
single agent of via merger of the companies) would manage gas flows for entire zone
ensuring that a gas balance across the zone is achieved on a daily basis.
This model will require significant political will from all four governments in order that the
market zone can be created and the necessary level of co-operation can be established.
The concept provides simplicity and flexibility for shippers and reduces barriers to entry.
Effectively, from the shipper perspective, the complex operational, commercial and
political issues are ‘hidden’, but will still need to be resolved.
One of the benefits of the EBZM model would be an enlarged, integrated market with a
demand of approximately 9bcm per annum. However, this is still well short of the Gas
Target Model aspirations of 20bcm per annum.
The main costs of this model would be the significant effort and risks of redistributions
between countries that might be the result of a single system operation, a single Network
Code and a single IT interface. The NRAs, charged with national consumer interests,
would need to cooperate closely in order that the requirements to balance national
interests and the interests of the zone can be achieved. It is likely that the Agency for the
Cooperation of Energy Regulators (ACER) might need to resolve any disputes.
Complex arrangements would be required in order that the allowed revenue for each TSO
can be recovered from transmission charges. The single zone implies a loss of IPs within
the zone requiring entry-exit charges at other points to ensure revenue recovery for each
TSO. If the TSOs are not combined then this raises the issue of how best to arrange
inter-TSO compensations requiring agreements between the NRAs as to how revenues
would be redistributed to ensure each TSO receives appropriate revenue. Given that
cross-border flows may be quite large when compared with gas demands these
redistributions may need to be significant.
A potential IP between the zone and Poland would allow gas nominated for entry onto the
zone to be offtaken at an exit point within the zone or to be traded at the zonal VTP. It is
possible that the zone could operate as a form of satellite market, an idea emerging as
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part of the Gas Target Model II deliberations, to the emerging Polish trading hub and
exchange.
Whilst the EBZM model may appear to offer the greatest potential to deliver a functioning
wholesale market, its complexity and requirement for cooperation are likely to be
challenging. An integration of this scale has not, in our knowledge been attempted in any
other gas markets to date.
We note that the Common Arrangements for Gas (CAG) project that has attempted to
create a fully integrated gas market on the island of Ireland covering both the Republic
and Northern Ireland has stalled and has made little progress since 2012. This is despite
a memorandum of understanding between the relevant governments and a successful
integration of the electricity markets.
Costs and benefits across the difference Baltic countries are unlikely to be closely aligned
necessitating difficult discussions about who shall pay for the necessary costs to generate
the fully integrated market. Issues of national governance and sovereignty may therefore
render the fully integrated EBZM model unachievable as a first step.
A summary of the requirements of the three market models is shown in Figure 4.
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Cooperation with other Baltic states
Wholesale market arrangements
Legislative and Regulatory Framework
Figure 4 – Summary of market model requirements
National market model
Interconnected National market
model
East Baltic Zone Market model
Unbundling of TSO
Required
Required
Required
Market Rules
FNC required as main contract
between market participants and
TSO and contains commercial
market rules and obligations on
market participants. Oversight by
the EA
FNC required to as main contract
between market participants and
TSO and contains commercial
market rules and obligations on
market participants. Oversight by
the EA
Single Network Code for the EBZM
developed jointly by the TSOs.
Administered by a TSO cooperative
body or single EBMZ TSO.
Oversight by NRAs or a cooperative
body/committee of the NRAs
Market participant roles
Defined in the NGMA and
oversight of compliance by the EA
Defined in the NGMA and
oversight of compliance by the EA
Defined in the NGMA and
oversight of compliance by the EA.
Additional requirement to develop
consistency across EBZM
NRA Role
Responsible for national market
oversight and enforcement
Responsible for national market
oversight and enforcement and
some cooperation with other East
Baltic NRAs
Role to be clarified in light of the
requirement for the EBZM NRAs to
cooperate and take a consistent
view/activity across the entire
zone
Alternative supply
source
LNG regasification
LNG regasification Balticconnector
LNG regasification Balticconnector
other LNG into the zone
GIPL
Required for Entry Point and Exit
Point Capacity and for EU
Balancing and Tariffs Network
Codes
Required for Entry Point and Exit
Point Capacity and for EU
Balancing and Tariffs and CAM,
CMP and Interoperability Network
Codes
Required for Entry Point and Exit
Point Capacity into the zone and
for EU Balancing and Tariffs and
CAM and CMP Network Codes.
Implementation of the
Interoperability Network Code
required for GIPL interconnection
Interconnection Points
arrangements
Not required
Required
1.Finland and Estonia
2. Estonia and Latvia
3. Latvia and Lithuania
4. Lithuania and Poland (potential)
Required for GIPL
Lithuania and Poland
Tariffs
Required for Entry and Exit Points
No requirement for revenue
sharing arrangements
Required for Entry and Exit Points
and for bundled capacity at the IP
with Estonia.
Revenue sharing arrangements
required for the IP
Required for Entry and Exit Points
into the EBZM and for bundled
capacity at the IP with Poland.
Complex tariff arrangements and
revenue sharing mechanisms
Government
National only
Cooperation with Estonia
regarding the Balticconnector
Cooperation with Estonia, Latvia
and Lithuania to agree system
operation at the zonal level
National only
Cooperation with Estonian NRA to
agree arrangements at the IP and
TSO revenue sharing
Cooperation with all NRAs in the
zone to agree complex tariff and
revenue sharing mechanisms for
the TSOs.
Potential to create a EBZM
regulatory oversight
body/committee
National only
Cooperation with Estonian TSO to
bundle capacity and agree
Interoperability arrangements at IP
Cooperation with all EBZM TSOs to
agree system operation and
management arrangements.
Potential to create a single TSO for
the EBZM
EU compliant
arrangements
NRA
TSO
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5.
EVALUATION OF THE POTENTIAL MARKET MODELS
This section contains an initial high-level evaluation of the potential market models to
meet the requirements of compliance with the Third Energy Package. An analysis of the
transmission networks and the capabilities of the networks to facilitate bi-directional cross
border flows has not been carried out. Neither has a detailed cost benefit analysis been
undertaken. The initial evaluation serves only to give a high-level overview of the
potential qualitative benefits of the potential market models alongside a view on the
complexities and issues that may be encountered in implementation.
5.1
Potential to establish a functioning wholesale market
Without new gas supply sourcing routes, which may come via a regional LNG terminal
(either direct into Finland or into another Baltic country assuming adequate
interconnection) or via pipeline interconnection to other parts of Europe (e.g. via the GIPL
link to Poland) a sustainable functioning gas market in Finland is unlikely.
Therefore, each of the market models assumes an enhancement of gas supply sourcing.
The establishment of either balancing platforms or trading platforms will better facilitate
the development of a short-term functioning wholesale market provided that sufficient
market players have access to short term gas flexibility. This can come from the supply
side (e.g. new gas importation or a redistribution of imported contracted gas (via, for
example voluntary Gas Release Mechanisms) or via demand side flexibility. Of the three
models this will however, be most limited in the NM model. The relatively small size of the
Finnish market in isolation may not be sufficient to attract many new entrants.
The INM model should attract more new entrants into each of the national markets. For
example, national incumbents would be able to enter the other Baltic states’ national
markets. The new rules should also be structured to encourage further new entrants.
Whilst any emergent liquidity would still be split across the four national VTPs a short term
flexibility market will at least provide a foundation for a fully functioning market. As
experience develops forward trading may emerge although, consistent with expected Gas
Target Model II conclusions the Baltic states may only be able to achieve satellite market
status when compared with major markets, for example at TTF.
The EBZM model has the greatest potential to deliver a functioning wholesale market as
liquidity generated by a larger overall market size would be concentrated on a single VTP
for the zone. It is not clear that a market size of around 9 bcm per annum would be
sufficient to support a deep, liquid forward market. However, the complexities with
achieving this model may preclude it from further consideration, at least as a first step.
5.2
Security of Supply
The additional gas supply sourcing assumed within each of the models will improve
security and diversity of supply.
The INM model has advantages over the NM model as it allows a connection to Estonia
and could allow gas to flow from south to north assuming that sufficient infrastructure is
developed to allow gas to flow from the Latvian storage facility at Inčukalns to Finland.
Third-party access to Inčukalns could be a significant contributor to a properly functioning
market in each of the Baltic states. The INM model also creates an environment that is
more attractive to new entrants.
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The EBMZ model has no particular advantages over the INM model from the perspective
of physical security of supply and may result in a requirement for more physical balancing
actions by the zone’s TSO in order to ensure that physical flows meet commercial flows.
5.3
Complexity of arrangements
The inherent complexities of each model will result in different impacts on each
stakeholder.
The NM model requires legislative changes, the unbundling of Gasum Oy and the
establishment of third-party access market rules including entry-exit zone, general
capacity, balancing and tariff arrangements. The changes are considerable but necessary
to deliver any chance of a properly functioning market. However, this model does not
require the additional obligations associated with an IP that would result in cooperation
between Finish and Estonian TSOs and NRAs. Shippers are just dealing with national
arrangements and a single TSO and IT interface.
In the INM model, additional requirements include the establishment of an IP (between
Finland and Estonia). Thus IP requirements from CAM, CMP and Interoperability EU
Network Codes will need to be satisfied. The TSOs will have to develop bi-directional
bundled capacity at the IP and the NRAs will be required to cooperate in order that
revenue from the sale of bundled capacity is allocated to each TSO in a nondiscriminatory way. Shippers will need to purchase IP capacity via multiple auction
mechanisms that will be facilitated by the TSOs (probably via PRISMA or an alternative
platform). Shippers will need to satisfy licensing and/or contractual requirements in other
relevant Baltic states to purchase IP capacity at the other IPs. Shippers will be required to
develop a number of different IT interfaces and sign up to additional national Network
Codes. Whilst this model is more complex than the NM model, it does have greater
potential benefits to shippers and end users. Some light co-ordination in the Baltics,
promoted by national governments but delivered by NRAs and TSOs in conjunction with
wider market players could ensure sufficient compatibility of rules and processes to
maximise opportunity for future Baltic regional market functioning.
The EBMZ model will significantly reduce the complexity for shippers as they will have a
single code, single IT interface and will interact with a single TSO. Capacity booking will
be limited to the zone’s entry and exit points as IPs between the four states will not be
required. However, the shipper benefits will need to be offset by the significant complexity
“behind the scenes” required to implement the arrangements. The level of government,
NRA and TSO cooperation necessary may be challenging, possibly even unrealistic, and
potentially a major risk to successful implementation. Whilst there may be less complexity
in a single IT interface and single code, the establishment of such may be so complex and
difficult as to cause significant delays with the risk of non-compliance with EU
requirements.
All three models imply considerable change. Ultimately if agreements are not made and
decisions taken swiftly, this may result in a situation where compliance with the Third
Energy Package is not achieved within proscribed timescales following the removal of the
derogation. This may subsequently result in EU enforcement orders and fines if Finland is
not able to achieve compliance, potentially where this is due to the actions or inactions of
other stakeholders. This is a real risk in an integration project of this type.
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5.4
Cost
Baseline costs in the NM model will include legislative and contract development
(including NGMA changes and FNC), IT systems and interface development,
consultancy/project management and regulatory change.
Costs in the INM model will be expected to be higher as additional arrangements will be
required at the IP in addition to the financing of the Balticconnector through tariffs. Costs
will be incurred in all four national markets to develop network codes and IT interfaces.
There may be some cost savings in the EBZM model as there will be a single code and
single IT system rather than 4 national codes and systems. However, the costs to
establish the market zone, the single code and single IT system should not be
underestimated as decision-making processes will be more complex, lengthy and will
involve decisions of major significance to four countries. Experience of such cross-border
co-ordination suggests that the option would require major political commitment from all
four national governments.
Some operational costs may be higher in the EBZM model in order that the physical
regime can reflect the flexibility afforded to shippers under the commercial regime. This
could result in higher balancing and system management costs. Implementing the EBZM
would therefore require an assessment that the value of the overall benefits exceeds the
costs. Furthermore, if infrastructure is developed to avoid these operational costs or to
enhance further the functioning of the market then these will need to be recovered through
tariffs.
Our high-level indicative evaluation of the models from the perspective of achieving
compliance with the Third Energy Package requirements in Finland is shown in Figure 5.
Figure 5 – Indicative High-level Summary of market models
Note: This evaluation does not assign a weighting to each of the categories meaning that a final evaluation must have
regard to which category is the most important to Finland
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6.
CONCLUSIONS AND RECOMMENDATIONS
This study has identified the main building blocks that are required in order to deliver a
competitive gas market in Finland and has considered how these building blocks may be
applied in three alternative market models.
In each of the national models (NM model and the INM model) there exists a set of
common building blocks that must be addressed regardless which model is preferred:

a robust legislative and regulatory framework to support market liberalisation,
including;
 unbundling of the vertically integrated monopoly;
 establishment of third-party access rights for transmission and LNG regasification
(once it exists);
 creation of a clear roadmap for market opening;
 a requirement to develop a FNC to contain all commercial rules and obligations
on market participants implementing entry-exit zones, the general capacity
requirements plus balancing and tariff arrangements;

secure enforcement powers for the Energy Authority for the new market design; and

alternative gas supply sourcing.
These building blocks would provide the necessary foundation for a properly functioning
wholesale market based on the EU Balancing Network Code and the forthcoming EU
Tariffs Network Code.
However, under the NM model, it is not clear that the Finnish market is sufficiently large
and attractive to generate sufficient market player interest to start and sustain a
functioning gas market.
With further physical pipeline interconnection a larger regional market might be
considered. If the INM model is selected as the best option for Finland then there will be
an additional requirement to develop rules at the Interconnection Point with Estonia that
are compliant with the EU CAM, CMP and Interoperability Network Codes.
In either the NM model or the INM model, the legislative framework and the requirement
to unbundle Gasum Oy should be achieved before the alternative supply source is in
existence. This would assure wider market players and potential new entrants of the
independence of the new unbundled TSO. The new regime should be implemented to
coincide with the commencement of first gas from the alternative supply source.
It may be preferable for unbundling to take place as soon as is practicable so that the
roles of the unbundled Gasum are clarified prior to investment decisions being required for
the LNG regasification facility and the Balticconector. This would give additional certainty
to potential investors in both infrastructure projects and remove an element of regulatory
risk.
The INM model offers benefits over the more limited NM model as the potential market
size is larger and the potential for new entrants is increased. The costs of delivering the
INM model will be higher however as there are incremental codes and systems that will be
required at the IP with Estonia. However, the incremental costs might be modest and
therefore efficient in the context of the wider benefits arising from competition and
increased market integration.
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Whilst the EBZM model appears to offer additional benefits over the INM model, including
the potential to reach a larger market size, it requires a significant level of coordination
amongst four markets and an unprecedented level of cooperation between governments,
NRAs and TSOs. The risks of high costs, complexity and longer implementation timelines
should be noted. This outcome might provide a longer term vision that could be
implemented following either NM or INM.
On balance, it would seem therefor that the INM model offers the benefits of access to a
larger and less fragmented market when compared to the NM model and limited
complexity when compared to the EBZM model. However, this is based on the high-level
qualitative review that has been undertaken as part of this study. A more rigorous
analysis of the three options will be required before a final recommendation is made. This
would involve a more thorough review of the other Baltic markets and an examination of
available infrastructure and capacity availability to flow gas under a number of scenarios
in each of the models. Involvement of NRAs and TSOs at an early stage in the
development of proposals would have merit and enable “buy-in” to the initiative.
However, since each of the market models contain common elements such as the
requirement to unbundle the vertically integrated monopoly and to set a clear market
opening timetable, this should not prevent the Natural Gas Committee from making a
proposal to change the NGMA for these building blocks and starting the necessary
enabling processes.
The gas market arrangements that will be required will depend on the market model that
is selected. There is a high degree of commonality and clear incremental steps that are
required between the NM model and the INM model and these could be reflected in the
revised NGMA.
It will be more difficult to draft legislation that caters for the EBZM model as an additional
option as the fundamentals of the market arrangements will need to consider the
complexity of government, NRA and TSO cooperation. It is currently unclear how this
could develop without discussions with the other Baltic governments.
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ANNEX A – ADDITIONAL INFORMATION
A.1
Ownership Unbundling Options
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A.2
LNG Operational Models
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A.3
Entry-Exit Principles
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A.4
European Trading Hubs
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A.5
Market Arrangements requirements under EU Network Codes
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A.6
Market Opening Examples
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QUALITY AND DOCUMENT CONTROL
Report’s unique identifier: 2015/018
Quality control
Role
Name
Date
Author(s):
John Williams
January 2015
Paola Lualdi
Approved by:
John Williams
January 2015
QC review by:
Matina Delacovias
January 2015
Document control
Version no.
Unique id.
v1_0
2015/018
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Date
January 2015
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