regulation of european gas transmission system operators · 2017. 6. 14. · 4.2 the opening value...

Regulation of European gas transmission system operators A FINAL REPORT PREPARED FOR DTE AND MINEZ

January 2005

© Frontier Economics Ltd, London.

i Frontier Economics | January 2005

Regulation of European gas transmission system operators

1 Introduction ......................................................................................... 1

2 Background on the gas industry ..........................................................3

2.1 Corporate ownership and structure ..........................................................3

2.2 Interconnection in Europe.........................................................................5

2.3 Regulatory institutions ................................................................................5

3 Regulation of access arrangements ................................................... 10

4 Calculating the regulatory asset base................................................. 15

4.1 General framework................................................................................... 15

4.2 The opening value of the RAB............................................................... 20

4.3 Rolling forward the asset base ................................................................ 27

4.4 Rolling forward the RAB for overspend and underspend.................. 36

5 Calculating the WACC .......................................................................37

5.1 Cost of capital methodology ................................................................... 37

5.2 Cost of equity ............................................................................................ 37

5.3 Cost of debt ............................................................................................... 38

5.4 Gearing ....................................................................................................... 38

5.5 Inflation and taxation adjustments......................................................... 39

6 Key findings and implications for The Netherlands .........................47

6.1 General regulatory framework ................................................................ 47

6.2 Calculation of the RAB............................................................................ 48

6.3 WACC ........................................................................................................ 53

6.4 Conclusions on the Dutch regime.......................................................... 54

Annexe 1: Glossary of key terms .................................................................55

Annexe 2: Austria ........................................................................................57

Annexe 3: Belgium......................................................................................69

Annexe 4: France......................................................................................... 81

Annexe 5: Germany..................................................................................... 91

Annexe 6: Ireland ...................................................................................... 103

Contents

ii Frontier Economics | January 2005

Annexe 7: Italy ...........................................................................................117

Annexe 8: Spain......................................................................................... 127

Annexe 9: UK ............................................................................................ 139

Contents

iii Frontier Economics | January 2005

Regulation of European gas transmission system operators

Figure 1: Difference between standard and non-standard index approach.......... 17

Figure 2: The German gas wholesale market – shareholders and shareholdings of GTS ........................................................................................................................ 92

Table 1: Background details on European gas transmission system operators ......4

Table 2: Gas interconnectors in Europe.......................................................................5

Table 3: Regulatory institutions......................................................................................9

Table 4: Regulation of gas transmission tariffs ......................................................... 12

Table 5: Structure of gas transmission charges ......................................................... 13

Table 6: Calculation of the regulatory asset base...................................................... 19

Table 7: Calculation of the opening value of the regulatory asset base................. 26

Table 8: Depreciation and investment allowances in the regulatory asset base ... 35

Table 9: WACC values.................................................................................................. 39

Table 10: Calculation of the WACC........................................................................... 45

Table 11: Methodology for calculating the RAB given regulatory regime............ 48

Table 12: Methodology for calculating the initial value........................................... 50

Table 13: Depreciation rules........................................................................................ 52

Table 14: WACC comparison ..................................................................................... 53

Table 15: Basic facts on GTS operator – Austria..................................................... 57

Table 16: Technical information on gas sector - Austria ........................................ 58

Table 17: Regulatory institutions - Austria ................................................................ 60

Table 18: Regulatory regime - Austria........................................................................ 62

Table 19: Methodology used to calculate the RAB - Austria.................................. 64

Table 20: Treatment of capital expenditure in the RAB - Austria ......................... 65

Table 21: Determination of the WACC – Austria ................................................... 67

Table 22: Basic facts on GTS operator - Belgium.................................................... 69

Table 23: Technical information on gas sector - Belgium....................................... 70

Table 24: Regulatory institutions - Belgium .............................................................. 72

Tables & figures

iv Frontier Economics | January 2005

Table 25: Regulatory regime - Belgium...................................................................... 74

Table 26: Methodology used to calculate the RAB - Belgium................................ 77

Table 27: Treatment of capital expenditure in the RAB - Belgium ....................... 78

Table 28: Determination of the WACC – Belgium.................................................. 79

Table 29: Basic facts on GTS operator - France ...................................................... 81

Table 30: Technical information on gas sector - France ......................................... 82

Table 31: Regulatory institutions – France................................................................ 83

Table 32: Regulatory regime – France........................................................................ 85

Table 33: Methodology used to calculate the RAB - France .................................. 87

Table 34: Treatment of capital expenditure in the RAB - France.......................... 88

Table 35: Determination of the WACC – France .................................................... 89

Table 36: Basic facts on GTS operator - Germany.................................................. 91

Table 37: Technical information on gas sector - Germany..................................... 93

Table 38: Regulatory institutions – Germany ........................................................... 94

Table 39: Regulatory regime - Germany .................................................................... 96

Table 40: Methodology used to calculate the RAB – Germany ............................. 98

Table 41: Treatment of capital expenditure in the RAB – Germany .................... 99

Table 42: Determination of the WACC - Germany............................................... 100

Table 43: Basic facts on GTS operator - Ireland.................................................... 103

Table 44: Technical information on gas sector - Ireland....................................... 104

Table 45: Regulatory institutions - Ireland .............................................................. 107

Table 46: Regulatory regime – Ireland ..................................................................... 110

Table 47: Methodology used to calculate the RAB - Ireland................................ 112

Table 48: BGE's allowed regulatory capital value for Onshore Transmission Assets ................................................................................................................... 113

Table 49: Treatment of capital expenditure in the RAB - Ireland ....................... 114

Table 50: Determination of the WACC – Ireland.................................................. 116

Table 51: Basic facts on GTS operator - Italy......................................................... 117

Table 52: Technical information on gas sector - Italy ........................................... 118

Table 53: Regulatory institutions - Italy ................................................................... 120

Table 54: Regulatory regime - Italy........................................................................... 122

Tables & figures

v Frontier Economics | January 2005

Table 55: Methodology used to calculate the RAB - Italy..................................... 124

Table 56: Treatment of capital expenditure in the RAB – Italy ........................... 125

Table 57: Determination of the WACC – Italy ...................................................... 126

Table 58: Basic facts on GTS operator - Spain....................................................... 127

Table 59: Technical information on gas sector - Spain ......................................... 128

Table 60: Regulatory institutions – Spain ................................................................ 130

Table 61: Regulatory regime - Spain......................................................................... 132

Table 62: Methodology used to calculate the RAB - Spain................................... 135

Table 63: Treatment of capital expenditure in the RAB – Spain ......................... 136

Table 64: Determination of the WACC - Spain ..................................................... 137

Table 65: Basic facts on GTS operator - UK.......................................................... 139

Table 66: Technical information on gas sector - UK ............................................ 140

Table 67: Regulatory institutions - UK .................................................................... 142

Table 68: Regulatory regime - UK............................................................................ 144

Table 69: Methodology used to calculate the RAB - UK...................................... 147

Table 70: Transco's asset value (2002 price control).............................................. 148

Table 71: Treatment of capital expenditure in the RAB - UK ............................. 149

Table 72: Determination of the WACC – UK........................................................ 151

Tables & figures

1 Frontier Economics | January 2005

1 Introduction Frontier Economics was asked by DTe and Minez to review regulatory arrangements for gas transmission system operators (TSOs) in a selection of European Countries and to compare these to the arrangements used in the Netherlands. This paper summarises the findings of this research and places particular emphasis on the methodologies that were used to calculate the regulatory asset base and the return allowed on that asset base (the cost of capital). The research was undertaken between October and December 2004.

The comparison of methodologies, and the rationales provided by regulators for choosing one over another, are of interest to DTe and Minez as they begin the next review of prices for Gastransport Services (a wholly owned subsidiary of Gasunie). The comparisons will allow DTe and Minez to consider regulatory precedence in this area and to develop a better understanding of the benefits and costs associated with alternative methodologies. Furthermore, and importantly, DTe and Minez wish to consider whether there is a case for adopting a regulatory model which is consistent with that used in other countries to ensure that access arrangements do not distort decisions relating to interconnecting between, and transit across, countries. Our assessment of whether a change in DTe’s approach should be considered, given the methodologies used elsewhere, is presented in section 6.

The report proceeds as follows.

…

…

…

In Section 2 we briefly summarise the ownership and corporate structures of the gas TSOs and we examine the extent of interconnection across Europe today. We also provide a high-level overview of the regulatory institutions which are in place and explain whether or not a formal regulatory regime exists for third party access (TPA). Taken together this background information provides insight into the environment in which decisions are made and these factors do, in many cases, affect the decisions which are made about the methodologies used for restricting a TSO’s prices. It is therefore important when comparing Netherlands to other countries that these factors are borne in mind.

In Section 3 we compare the regulatory mechanisms that are used in each country for restricting the prices of the TSOs. The chose of mechanism influences the methodology used to calculate an asset value. Most notably, where an annual review is in place the limited time available influences decisions about the data to use when making this decision.

In Section 4 we provide a detailed review of the methodologies which are used to calculate a regulatory asset base for the TSOs and explain, where the information is available, why a regulator chose one methodology instead of another. Details are provided on the calculation of the initial value of the RAB, on the treatment of price indices and investment, on the depreciation rules used and on the treatment of historical overspend or underspend.

Introduction


…

…

In Section 5 a comparison is provided of the methodologies and numbers used to calculate the weighted average cost of capital (the WACC). This provides an indication of the return allowed on the asset base by regulators, although the actual return may in some cases differ from the calculated value.

In Section 6 we use the information in other sections to draw out key messages for the Netherlands on how regulatory methodologies compare across Europe. This comparison is used to assess whether there may be a case for changing the methodology used to establish GTS’s RAB for the next tariff review. Other factors, in addition to this cross-country comparison, will also need to be considered by DTe when deciding how to calculate this RAB value. In particular, decisions on other elements of the tariff ‘package’ (e.g. efficiency assumptions and the allowed WACC) will need to be considered alongside the RAB value when deciding on the appropriate balancing of consumer and shareholder interests.

Annexe 1 provides a glossary of the main terms used in the report. Annexes 2 to 9 provide detailed country studies on Austria, Belgium, France, Germany, Ireland, Italy, Spain and the UK These country studies provide the information for the comparative analysis presented in the main body of the report.

All information in this report relates to research undertaken between October and December 2004. Changes implemented by regulatory agencies since then are not reflected in the country description or in the main body of the report.

Introduction


2 Background on the gas industry

DTe and Minez will need to ensure that, when comparing the regulatory system in the Netherlands to that used in other countries, similar companies and regulatory regimes are being compared. For example, if a company is publicly owned this may influence the type of regulatory mechanism (e.g. high powered incentive scheme or not) which is used by the regulator. Similarly, if a government ministry is responsible for making regulatory decisions it may be faced with different duties and constraints than a regulatory authority which has been established as an agency which is independent of the government. These factors need to be considered when comparing the underlying methodology for regulating tariffs.

We briefly provide, in section 2.1, details of the corporate ownership and structures of the gas TSOs in Europe. In section 2.2, a review of the extent of interconnection between countries is provided. An overview of the regulatory institutions is provided in section 2.3.

2.1 CORPORATE OWNERSHIP AND STRUCTURE

Table 1 provides information on the ownership and structure of the TSOs. Specifically we make a distinction between companies that are owned by private shareholders and those that are publicly owned. Only one country has a wholly owned government company (Ireland), but two others have companies where the government retain a majority shareholding (Austria and France). All others are primarily owned by private shareholders (or, in the case of Spain, will be by 2007). The ownership structure can have a bearing on the decisions which are made about the general regulatory mechanism to use (in particular the role of incentive mechanisms), the methodology used to calculate the regulatory asset base (in particular whether shareholder returns are of most interest) and the required return on capital.

We also indicate whether or not the TSO is part of a larger group structure and, if so, whether it has links with other activities in the gas sector, in other regulated utility sectors and/or in other industries. The fact that a TSO is part of a larger corporate structure is only of relevance to the extent that it requires the regulator to ensure that the regulatory operations of the gas transportation business are ring-fenced from other operators and that separate accounting information is available. It appears that in all countries reviewed a separate transmission licence-holder exists – even if it is part of a larger group – and all endeavours are made to ensure that accounting information provided is for the regulated transmission company only. We have not reviewed this issue further here as we assume that suitable arrangements will be in place in the Netherlands when GTS’s tariffs are reviewed.

Background on the gas industry


Au

stria

Belg

ium

Fra

nce

Ge

rma

ny

Ire

lan

d

Italy

Spain

UK

Number of TSOs

Six One Three Five One Three Two

(one national)

One

Ownership Primarilypublic

Primarily private

Primarily public

Primarily private

Public Private Public/Private Private

Private by 2007

Corporate structure

All part of wider group that undertake many activities including gas distribution.

Part of wider group that undertakes other gas activities.

All linked to Gaz de France (one of the TSOs) and Total.

All part of wider groups that undertake many other activities, including other gas activities and in other utility sectors.

Integrated gas company which also holds gas distribution and supply licences. Also has interests in CHP and telecommunications infrastructure.

Part of larger gas companies which also undertake, among other things, natural gas production.

Company involved in other gas activities. Part of wider group (e.g. BP) that is involved with several other activities worldwide.

The parent company, NGT, also has interests in gas distribution, responsibility for system operations (i.e. balancing of gas flows on network) and owns the electricity transmission network.

Table 1: Background details on European gas transmission system operators

Source: Country studies



2.2 INTERCONNECTION IN EUROPE

Table 2 summarises the extent of interconnection between gas TSOs in Europe. This reconfirms the view that regulatory access arrangements are likely to affect transportation across several interconnected countries as well as within a country. For example, the cost of transporting gas from the Czech Republic to the UK will vary depending on which route is taken and hence which regulatory agencies affect the charges paid in transit. A review of the case for consistent methodologies for regulating gas transportation charges may therefore be warranted.

Country Connected to

Austria Germany and Italy

Belgium France, Germany, Luxembourg, Netherlands, Norway and UK

France Belgium, Germany, Norway, Spain and Switzerland

Germany Austria, Belgium, Czech Republic, Denmark, France, Luxembourg, Netherlands, Poland and Switzerland

Ireland UK

Italy Austria, Slovenia, Switzerland and Tunisia

Spain France, Morocco and Portugal

UK Belgium and Ireland

Table 2: Gas interconnectors in Europe


2.3 REGULATORY INSTITUTIONS

Table 3 summarises the institutions which are responsible for regulating the tariffs of gas TSOs in different countries. We indicate whether or not the regulatory agency is independent from the government, and we provide a brief summary of the legal duties placed on the regulator with regard to the regulation of gas transportation charges. More details on these duties can be found in the individual country studies in Annexes 2 to 9. We also indicate whether or not the regulator’s decisions can be appealed and, if so, whether that appeal body is a court of law or an alternative institution.

These factors affect the degree of discretion that a regulator has over the mechanism used to regulate tariffs and over the precise methodologies used to set the tariff restraints. Discretion is expected to be higher if the regulator is



independent, if the legal duties are quite general and if the grounds for appeal to another body are limited. In contrast, the regulator’s decision-making powers may be expected to be more limited or constrained if the legislation specifies the type of regulatory mechanism to be used and, potentially, includes details of the way in which that mechanism is to be applied, or if appeal to another body is a straight-forward and common process. It may also be the case that the regulator has greater discretion when it is part of the government if the Ministry involved is less accountable for its actions than an independent regulator. The relationship between the regulator and the government – both in terms of whether or not the regulator is an independent entity and the degree of accountability that regulators bear for their decisions – is therefore important in influencing the amount of discretion and flexibility that exists in decision-making.

The choices available to a regulator in one country may therefore be different to those that can be considered by DTe. For example, a number of regulators are provided with legal instructions or government orders which lay out the framework of how charges are to be regulated in quite some detail (with explicit formulas included in the government orders in Spain). These government instructions may even specify the methodology for calculating the asset value and the return to be allowed on it and, hence, the regulators do not have the option of considering alternative methodologies. Furthermore, such formal instructions from the government ministry may also suggest that factors other than economic principles have affected decisions underlying the setting of regulated charges. These details are not disclosed by governments or regulators but the potential that they have had an influence on the final decision on charges should be borne in mind when assessing the approach adopted in other countries.



Au

stria

Belg

ium

Fra

nce

Ge

rma

ny

Ire

lan

d

Italy

Spain

UK

Established regulatory agency?

Yes Yes Yes No - self-regulation

Yes Yes Yes Yes

Date when regulated TPA introduced

October 2002 November 2002

January 2003 n.a. October 2003 (first regulated

prices)

2000 1998 1986

Name of regulatory agency

(a) E-Control ECK (decision-making body). (b) E-Control GmbH (operative branch that proposes policy to decision-making body)

(a) CREG (federal)

(b) VREG (Flemish region)

(c) CWaPe (Walloon region)

(a) Government (decision-making body) (b) CRE (operative branch that proposes tariffs to government)

Bundeskartellamt (Competition Authority)

CER (a) AEG(detailed regulation)

(b) Ministry of Productive Activities (set general framework of regulation)

(c) Regional governments (concurrent powers)

(a) Ministry of Economy (decision-making on tariffs and sets methodology in laws)

(b)CNE (operative branch that government consults with on proposed tariffs)

Ofgem

Status or regulatory agency

Independent regulatory agencies

Independent administrative authority

(a)Government ministry

(b)Independent administrative authority

Independent institution

Independent regulatory agency

(a)Independent body (b)Government ministry

(a)Government ministry

(b)Public body with own legal responsibility

Independent regulatory agency



Au

stria

Belg

ium

Fra

nce

Ge

rma

ny

Ire

lan

d

Italy

Spain

UK

Regulator’s duties with regard to price

Law requires regulator to set prices that are cost reflective and efficient.

CREG approves proposed

annual tariffs. Able to disallow costs that

are considered

‘unreasonable’.

Methodology set out in

Royal Decrees.

CRE proposes tariffs to

government who issues a

legal decree on decision

(following consultation).

Ex-post intervention with pricing decision

if there is a dispute about whether or not

tariffs reflect the requirements of the Association agreement – no

precedence.

General duties to protect consumer interest, promote

competition, promote

safety and efficiency;

ensure security of

network and capacity -

discretion over form of price regulation.

Law requires prices to be set to ensure tariffs

are cost reflective and

allow a fair return to be earned on

assets. Law requires AEG to set tariffs in line with these

principles.

Methodology for regulating tariffs set by Ministerial

Order and implemented by CNE. Tariffs are set to ensure that

owners can recover costs of investments over lifetime of assets, earn a reasonable return allowed on

financial resources; and

provides incentives for

efficient management and

productivity improvement which is to be

shared with users and consumers.

General primary duty

to protect consumer interest - discretion

over form of price

regulation.



Au

stria

Belg

ium

Fra

nce

Ge

rma

ny

Ire

lan

d

Italy

Spain

UK

Name of appeal bodies

(a) ECK for decisions of ECG. (b)Constitution-al and administrative courts for ECK decisions

Conseil d’Etat

(a)Cour d’appel of Paris (b)Conseil d’Etat

Higher Administrative Court

(a)Ministerial Appointed Appeal Panel (for individual case) (b)High Court for judicial review

Administrative courts

(a) Ministry of Economy hears appeals against CNE decisions. (b) Spanish Tribunal (Audiencia Nacional) hears appeals against Ministry decisions

(a)Compet-ition Commission (b) Judicial review to High Court

Status of appeal bodies

(a) Regulatory body

(b) Supreme court

Court of law Courts of law Court of law (a)Government appointed panel. (b)Court of law

Court of law (a)Government ministry. (b)Court of law

(a)Independent appeal body (b) Court of law

Table 3: Regulatory institutions Source: Country studies



3 Regulation of access arrangements

In 2002 it was agreed, based on a European benchmark, that gas transportation rates in the Netherlands could decrease by 5% per annum (nominal) for the next four years. A review of gas transport tariffs is therefore forthcoming for the second regulatory period starting in 2006 and DTe is expected to use an ex-ante cost-plus regulation method as the starting point for this review. This starting point reflects the DTe’s duty to ensure that GTS’s rates reflect costs.

Other regulatory methods are available to regulators and a range of alternatives are used for gas transmission tariffs in Europe. The main choices are to:

•

•

•

• •

•

review tariffs annually or at periodic intervals, before they are implemented, to ensure that allowed revenues are sufficient to cover budgeted costs (ex-ante cost-plus regulation);

review tariffs at periodic intervals, before they are implemented, to ensure that allowed revenues are sufficient to cover expected efficient costs and set an allowed annual change in the tariffs for a fixed period of time that is longer than one year (ex-ante price cap regulation). In practice, the calculation of the allowed cap on tariff changes may involve similar calculations to the system of ex ante cost-plus regulation; and

review tariffs annually or at periodic intervals, after they have been implemented, to ensure that they meet established legal principles (ex-post regulation).

As shown in Table 4, all options have been used by one or more regulators for gas transportation charges in Europe. Two countries use an ex-ante price cap mechanism, five use an ex-ante cost-plus mechanism and Germany has a self-regulation regime which involves ex-post assessment by the competition authority if required.

However there is variation in the way in which each regulatory regime is implemented in practice, largely determined by the number of years that tariffs are fixed for. Most notably:

Austria, Belgium and France have cost-plus regulation with annual revisions to tariffs;

Italy and Spain have cost-plus regulation with the methodology for calculating allowed revenues determined at four year intervals but the allowed level of tariffs is reviewed annually; and

Ireland and the UK have price cap regulation with the methodology and tariff levels fixed for a four or five year period.

The Netherlands has cost-plus regulation with revisions to tariffs after four years.

In determining or assessing allowed revenues, the regulatory agency will typically assess the level of operating expenditure and capital cost. Capital cost is most often measured as depreciation charge plus the return earned on a chosen asset base.

Regulation of access arrangements


Au

stria

Belg

ium

Fra

nce

Ge

rma

ny

Ire

lan

d

Italy

Spain

UK

Form of constraint on prices

Ex-ante cost plus

Ex-ante approval of proposed

tariffs using cost plus

methodology

CRE use cost plus

methodology to determine tariffs which

are proposed to government

for formal approval

Tariffs expected to

meet principles laid

out in Associated Agreement.

No constraint set by a regulator

Ex-ante price cap

Ex-ante cost plus (although

this terminology is not formally used by the regulator)

Ex-ante cost plus (although

this terminology is not formally

used)

Ex-ante price cap

Frequency of price control

Tariffs can be reset at any time

Annual Annual (mayextend to 18

months)

Tariffs reset periodically by

companies themselves

Ex-post review by competition

authority in case of

dispute (no precedence)

4 years Tariffs assessed on

an annual basis.

Regulatory methodology assessed and

revised by AEG every four

years.

Regulated transportation toll revised on

an annual basis.

Regulatory methodology assessed and

revised by Ministry every

four years.

5 years

Coverage of price restraint

National transmission

costs allocated across

companies

Transportation tariffs for separate services

Transportation services only

Transmission only

Transmission only

Transportation only

Regasification, storage and

transportation.

Transmission only



Au

stria

Belg

ium

Fra

nce

Ge

rma

ny

Ire

lan

d

Italy

Spain

UK

Methodology for assessing allowed change in price/price level

Building block –

consider operating

expenditure; depreciation; and return on asset base

Building block - reasonable

costs assessed by considering operating

expenditure, depreciation

and fair return on capital.

Building block – proposed tariffs set to

cover operating and

capital expenditure and a return

on assets

Building block approach for

short-distance tariffs (as per Associated Agreement, not set by a regulator);

Comparative assessment of tariffs for long-

distance tariffs.

Building block –

consider operating


Building block – allowed

revenues set to cover the initial

asset value (rolled forward by inflation);

efficient operational

costs undertaken

since the start of the

regulatory period; a return

on capital invested since the start of the

period; and technical-financial

depreciation of relevant assets

Building block – annual allowed revenues set on the basis of an

initial asset value (rolled forward by

inflation) plus net new

investment undertaken

since the start of the

regulatory period (rolled

forward by inflation).

Building block –

consider operating


Table 4: Regulation of gas transmission tariffs Source: Country studies



The underlying building blocks of cost-plus and price cap regulation are sufficiently similar to allow for comparisons to be made abut the methodologies used to calculate required capital costs. However, some differences do arise. We focus, in section 4, on the methodologies used to evaluate the asset base and in section 5 on the different cost of capital calculations which have been used.

We conclude that an ex-ante cost plus regime is the most common regulatory mechanism amongst the regimes that we have reviewed but the practical application of this methodology varies somewhat by country.

Tariff structures

We summarise in Table 5 the charging structures which are used in different countries. The structure of tariffs will, alongside the allowed level, affect decisions about how to transport gas from Country A to Country B across different countries.

In line with the European Gas Regulatory Forum (Madrid, September 2003), it appears that countries are now all moving towards an entry-exit charging structure and, hence, in the future there may be a consistent approach on this matter. In principle, the re-balancing of entry and exit charges should be undertaken on the basis of the marginal cost of capacity at each entry and exit point. However, re-balancing could also be used as a lever to load past costs (such as, for example, an over-inflated asset base) onto the national exit points whilst retaining competitiveness with other GTS operators at the exit points on the border with other countries. We have not reviewed whether these relative price effects have influenced the determination of the opening RAB.

Country Structure

Austria Post Stamp model, with capacity and commodity parts

Belgium Recently moved from point-to-point entry-exit system

France Broadly entry-exit within each of 8 balancing zones, separate charges for transportation between zones which include mixture of capacity and commodity based charges

Germany Notional path with option for traders to net out entry-exit differences within their portfolio to pay only for notional net flows

Ireland Moving from a notional path (point to point) capacity booking regime to an entry-exit regime

Italy Entry-exit, based on booked capacity and entry and exit points. Additional variable fee for gas quantities injected to or taken off the system

Spain Transportation toll made up of a capacity reserve component and a pipe conveyance component. Uniform for the whole country in line with volume, pressure and method of consumption

UK Entry-exit – details of structure and calculations published by Transco

Table 5: Structure of gas transmission charges

Source: Country Studies



4 Calculating the regulatory asset base

In 2002 DTe calculated a RAB for GTS. A key question for the next review of gas tariffs is whether the methodology used is appropriate or whether there is a case for changing it to ensure consistency with the approaches used in other countries. We therefore review, in this section, the methodologies which are used to calculate the RAB for gas TSOs in other countries. Implications for the methodology used for GTS are discussed in section 6.

A regulator makes a number of separate decisions when choosing the methodology for calculating the regulatory asset base. Specifically, the following questions are considered:

• • • •

…

What general framework should be used to calculate the RAB? (i.e. should a book value or index approach be used?)

If an index approach is used, how should the initial value of the RAB be calculated?

If an index approach is used, how should the initial value be rolled forward over time?

If expected net new investment is included in the RAB at a price review, how should the RAB be adjusted at future reviews to reflect any differences between actual and expected investment?

We consider each of these questions in turn in this section and present the alternative options that have been used by regulators when answering them.

We note that most regulators in Europe do not publish details on the methodology used to calculate the RAB and regulators in a number of countries have been reluctant to provide us with details as to why a particular methodology was chosen. It is also notable that in several countries only one review of tariffs has been undertaken and hence there is limited information available on the methodologies used to roll the RAB forward to reflect historic overspend or underspend.

4.1 GENERAL FRAMEWORK

A number of different options can be considered for calculating the regulatory asset base for a company. The main general frameworks that are used in practice are as follows.

Book value approach – the regulatory asset base in each year is set equal to the book value of the assets for the regulated business, as published in annual accounts. This may be equal to the book value as listed in the company’s statutory accounts or it may be an adjusted book value to ensure that only assets which are regulated are included. The asset value can change significantly from year to year, without there being any change in the underlying assets, if accounting revaluations arise. In this sense, the change in the book value of assets from one year to the next can reflect factors other than the value of net new investments.

Calculating the regulatory asset base


…

…

…

Index approach – the asset base in each year is set equal to the asset base in the previous year updated for annual investment and depreciation. The base for the first year of the valuation is called the initial or opening asset value and may be equal to, for example, the book value of the assets at the time, the market value of the company, or the replacement value of assets. The annual change in the asset value with this approach is equal to the value of net new investments during the year (or expected net new investments with a forward-looking regime). Accounting revaluations do not affect the asset value to the same extent with this approach as the initial value, once determined, is fixed in the calculation. Only new investments (additions) require revaluations and this can be undertaken at each review of prices.

Table 6 provides an overview of the general frameworks which have been used to calculate the RAB by regulators when setting restraints on tariffs for gas transmission system operators. Austria and Germany use a book value approach and Belgium, France, Ireland and the UK use a standard index approach. There is variation in the way in which the approach is applied in each country.

Of those countries that use a book value approach, Austria reviews the asset value annually and German companies review it periodically at the time that tariffs are reviewed.

Of those countries that use an index approach, Belgium and France revalue the RAB annually (so that the previous year’s actual investment costs are included) and Ireland and the UK review it periodically at the time that tariffs are reviewed. The efficiency properties of the index approach will therefore vary by country.

Italy and Spain use the asset base in a different way to other countries. Specifically the focus is on allowed revenues that are changed annually and the initial RAB set at the start of the four year regulatory period. All components of the allowed revenue calculation, including the initial RAB value, are rolled forward by inflation for each annual tariff review. However, net new investment is explicitly included as a separate item in the allowed revenue calculation rather than being included in the RAB itself. Net new investment is updated annually whereas the initial value of the RAB does not change, in real terms, for the four year regulatory period.

We refer to the frameworks used in Italy and Spain as a ‘non-standard index approach’ as the calculation of annual allowed revenues includes an initial asset value (which is fixed for each year of the four year regulatory period), the rolling forward of that asset value by inflation, and the addition of a value for capital investment incurred during the year. In this sense it is the annual revenue calculation which is rolled forward rather than the RAB itself but the underlying parameters and methodologies are similar to those which are discussed for the standard index approach.

The formulas used in Italy and Spain look different to those used in other countries, where the RAB itself is rolled forward by net new investment and the return on that RAB is used to calculate allowed revenues. The variation is summarised in Figure 1. Fundamentally both approaches have the same



economic effect – with the value of the total asset base (historic assets and new assets) being reduced by depreciation over time and increased by new investment – but the presentation of the information and the process involved is different. In particular, the regulatory agencies in Spain and Italy are keen to make the distinction between the opening value of the RAB (which is set every four years) and the level of net new investment (which is updated annually based on actual values) transparent.

Allowed revenue4

=

Operating expenditure4

+

Depreciation4

+

Return on RAB4

where:

RAB4

=

RAB3

+

Net new investment4

Allowed revenue4

=

Operating expenditure4

+

Depreciation4

+

Return on Initial RAB

+

Return on net new investment1

+


+


+


Figure 1: Difference between standard and non-standard index approach

Note: All values are assumed to be adjusted for inflation in this illustration (ie. all values are real)

Standard Index Approach

Year 4

Non-standard Index Approach

Year 4



Au

stria

Belg

ium

Fra

nce

Ge

rma

ny

Ire

lan

d

Italy

Spain

UK

Is a RAB used in determination of price restraint?

Yes Yes Yes Yes (underAssociated Agreement)

Yes Allowedrevenues calculated

using an initial value of the

RAB and annual

investment allowances.

The term regulatory asset base is not

formally discussed but analysis of

allowed revenue related to capital

investment is similar to the analysis of a

regulatory asset value. In particular, the allowed revenue calculation specifies

a revenue value related to assets

which existed prior to the introduction of

the regulated tariffs and a revenue value

related to investments which

have been undertaken since

then.

Yes



Au

stria

Belg

ium

Fra

nce

Ge

rma

ny

Ire

lan

d

Italy

Spain

UK

Framework Book value Index approach

Index approach

Book value Index approach

‘Non standard Index

approach’

See above for explanation

‘Non standard Index approach’

See above for explanation

Index approach

Timing of revaluation

Annual Annual Annual When tariffsreviewed

Four years Annual Annual Five years

Why was this framework chosen?

Pragmatism – believed to be

best approach

given costs need to be assessed annually

Same as framework

used in electricity.

Reflects the economic

replacement value of the

assets.

Not public information

Historical practice

developed in electricity – relates to

public procurement

rules of 1950s

Consistent with UK

approach

Focus is on ensuring that company can earn adequate

return on all capital

investment. Objective is to

ensure that required

investment is undertaken.

Detailed formula set by Ministry. Reason for choice not public.

Provide efficiency

incentives to company. Consistent with RPI-X

regime developed

for BT.

Table 6: Calculation of the regulatory asset base




We summarise here the reasons that regulators have provided for choosing one framework over another. Regulators do not appear to have a specified set of economic principles which are used to assess the preferred framework for calculating the RAB. Both the book value and index approaches appear to be considered appropriate for meeting a duty or objective that tariffs should be based on a cost-plus approach or, more generally, be cost reflective. Other practical considerations also affect the choices made by regulators, as summarised here.

Countries that have chosen the book value approach have tended to favour this framework because:

• •

• •

•

it is simple, particularly when tariffs are adjusted annually (Austria); and

such an approach has been used historically (Germany).

Countries that have chosen the standard index approach have tended to favour this framework because:

it provides the company with efficiency incentives (UK and Ireland);

it reflects the economic replacement cost of the assets (Belgium), although this clearly depends on how the initial value in the index approach is set; and

the application of this approach is required by the Ministry which specified the detailed formula to use (Spain).

With both options, a number of regulators also consider consistency with the framework chosen in other regulated sectors (particularly gas distribution and electricity) and consistency with the framework used in other countries as a justification for their approach.

The regulators in Italy and Spain were unable to provide an explanation as to why the framework used - which is different to the standard index approach - had been chosen. The Italian regulator emphasised however that the main objective was to encourage investment and to thereby provide guarantees that investment would be appropriately remunerated. In Spain the Ministry sets out the details of the framework in law and CNE are not in a position to change it.

We conclude that, amongst the regulatory regimes that we have reviewed here, the index approach is the most common framework used to determine the value of the RAB. There is some variation in how it is applied in Italy and Spain but the underlying parameters which are calculated are the same as those used in standard index approach. However, as discussed below, regulators have not applied the index approach in the same way and, in particular, there has been variation in the way in which they calculate the initial value of the RAB.

4.2 THE OPENING VALUE OF THE RAB

As noted in section 4.1, six of the eight countries considered in this report use an index approach to evaluate the RAB (although as noted the approach used in Italy and Spain is non-standard). In these countries the evaluation of the RAB involves four steps.



1.

2.

3.

4.

…

…

…

…

…

Calculation of the initial opening value of the RAB.

Rolling forward of that initial value by an inflation index.

Assessment of allowed investment and depreciation levels that are added to this initial opening value for the regulatory period1.

Determination of the opening value of the RAB at the start of the next regulatory period, taking account of any differences between actual and allowed investment (and hence depreciation) levels in the previous period.

We consider the first step here, the second step and third steps in section 4.3, and the final step in section 4.4.

4.2.1 Methodology for calculating the opening value

The main options that can be used to evaluate the initial opening value of the RAB are as follows.

Historic cost - the historic cost book value of assets are taken from the company’s accounts at the relevant date. Assets are valued at their original purchase price.

Indexed historic cost - the historic cost book value of assets in the accounts are inflated using a price index. The valuation is then based on the original purchase price rolled forward by inflation (which is likely to be different to the current purchase price which will also be affected by technological and market developments).

Adjusted historic cost (whether indexed or not) – the historic cost book value, or the indexed historic cost book value, are adjusted to reflect differences between the regulator’s decision on issues such as asset life, treatment of subsidies, and the allocation of common assets across integrated businesses, and the assumptions used in the accounts.

Replacement cost - the MEA or replacement cost value of assets is calculated at the time that regulation is introduced. An asset is valued as the cost of replacing it with one today that provides the same services and capacity as the existing one. The valuation therefore reflects current purchase prices and current technology. This is considered a reasonable estimate of the economic value of the assets.

Market value - the market value of assets over a specified period of time is used (i.e. the price paid by shareholders for the assets).

As shown in Table 7, two countries use the adjusted indexed historic cost approach (Ireland and Italy), Belgium use a replacement cost methodology and only the UK uses a market value approach. We also note that in Austria and Germany an historic cost approach is used to value the assets each year, with no adjustment made for inflation or technological change.

1 These values are added to the allowed revenue associated with the initial value directly in the allowed revenue formula in Italy and Spain rather than being rolled forward in the RAB.



The approach used in Spain is non-standard and is not transparent. The Ministry set a value for the allowed revenue that could be earned from the initial assets that existed at the start of the first regulatory period and this value was linked to the fixed costs of these assets. However, the methodology used to calculate this fixed cost or the allowed revenue associated with the initial assets is not public and the CNE emphasised that they were provided with a number by the Ministry and did not know how it was calculated. The approach in France is also not publicly available as the value was set by a commission established to value sale of Gaz de France assets for sale.

There is therefore no single methodology that is used by all regulators to calculate the opening value of the RAB. Furthermore, as discussed in more detail below, even though a number of countries choose a methodology that is between historic cost and current economic replacement cost, there is a great deal of variation in the methodologies used to index the value (e.g. Belgium use an MEA value, Italy index the historic cost using an investment deflator and Ireland use an indexed historic cost based on the CPI). The review of methodologies used by other regulators therefore does not, in itself, provide a clear signal to DTe as to which methodology is preferable for calculating the initial value of the RAB.

Limited information is available from regulators on why a particular methodology is chosen. The explanations that we have been able to obtain are summarised here.

…

…

…

…

The indexed historic cost approach is preferable because it is objective and provides a more stable revenue path than an estimate based on the replacement value of assets (Ireland).

The indexed historic cost approach is preferred because it brings the asset value closer to the current replacement cost value (Italy).

The replacement cost value approach is preferred because it ensures that the RAB reflects the economic value of the assets over time (Belgium).

The market value approach is preferable because it reflects the return required by shareholders on their actual investment. This allows for a trade-off to be made between returns to shareholders and the price paid by consumers (UK).

The varying comments indicate that the objectives of the regulator, and the conditions in which a company operates (including the ownership of the company) affect the choice of methodology. This partly explains why no single methodology is used by all regulators. In general, it is expected that a decision is made to move away from an economic valuation (i.e. an MEA value of the assets) in order to minimise the impact on consumer prices (an equity concern) or because the process required to determine an MEA value is considered too difficult (or subjective). However, regulators have indicated that indexing of the historic cost is preferable as it is closer to the current cost value of the assets.

We conclude that no single preferred methodology for calculating the initial value of the RAB emerges across the countries reviewed. A number of different accounting methodologies are used and a number of different adjustments are made by regulators before the initial value of the



RAB is determined. Furthermore, some regulators are simply provided with a value by the government and the underlying methodology is not known. It is expected that methodologies are chosen on the basis of a regulatory decision about the appropriate trade-off between the need to set a price which reflects the economic value of the assets and the need to limit the increase on consumer prices.

4.2.2 Practicalities of calculating the initial value

The practical process involved in calculating the initial value varies by country.

…

…

…

…

…

…

In Belgium, the company undertook a detailed asset inventory, taking account of current market unit prices and current technology to determine the MEA value of these assets.

In France, the initial value was set by a Commission established for a different purpose and the methodology used is not known.

In Ireland, the regulator took the historic cost book value of the assets from BGT’s accounts and adjusted these by the Irish consumer price index and for differences in the assumptions made about asset lives, the treatment of EU subsidies and the allocation of common assets across BGT’s businesses.

In Italy the companies are required to calculate the initial asset value and present the value to the regulator. Detailed guidance is provided on the methodology which should be used to determine the adjusted indexed historic cost value (see country study for details). The adjustment related to the need to take account of EU subsidies.

In Spain the allowed revenue related to the initial assets is set by the Ministry and it is not clear how the value was determined.

In the UK, the regulator took the current cost value of assets from accounting information provided by Transco and applied the calculated market-to-asset ratio to this value. The market value information was simply taken from publicly available stock market data.

4.2.3 Inflation indices

As noted above, both Ireland and Italy inflate the historic cost book value of assets to set the initial value of the RAB. The Irish consumer price index (CPI) is used in Ireland and a gross fixed investment deflator is used in Italy. The CER in Ireland stress that the inflation is required to ensure that the value reflects the real costs faced by BGT. Similarly, the AEG in Italy emphasise that inflation is required to ensure that the initial value is close to the replacement cost value of the assets. The replacement cost valuation used in Belgium also, implicitly, takes account of inflation as current unit prices are used in such an appraisal.



Belg

ium

Fra

nce

Ire

lan

d

Italy

Spain

UK

Methodology MEA value at start date plus investment and less depreciation for the first six months in the following year.

Set by la Commission Houri – methodology not public

Indexed Historical Cost of Assets

Inflated historic cost of assets

Set by Ministry - methodology used not public

Market value - current cost asset value adjusted by MAR

Why was this methodology chosen?

Reflects true economic replacement value of the assets. Consistent with methodology used in electricity sector.

Not public More objective than replacement cost methods and results in more stable revenue stream. Consistent with methodology used in other sectors and other countries.

Close to replacement cost value of existing assets

Not public – value determined by Ministry

Ensure shareholders earned return on their investment rather than on entire asset base. Allowed for redistribution between shareholders and consumers by allowing differentiation between economic value of assets and price for a number of years.



Belg

ium

Fra

nce

Ire

lan

d

Italy

Spain

UK

What practical assessment were involved in determining the opening value (e.g. asset plans assessed)

Company undertook detailed technical inventory and applied current monetary valuations to assets, taking account of available technology.

Not public BGT provided book value of asset base to CER, inflated by CPI. This was revised (see below) to determine the opening asset value.

Methodology set out in 2001 guidance document to companies on process of revaluation required for book value of assets in the financial statements.

Ministry determined valuation - details not publicly available on process involved.

Current cost asset value taken from accounts. Market value for transportation company calculated. Adjusted current cost asset value by MAR.

Starting point 31/12/2002 2001 September 2003 31/12/2000 31/12/2001 31/12/1991

Accounting approach

MEA Not public HCA, inflated by Irish Consumer Price Index

HCA, inflated by a gross fixed investment deflator

Not public MAR adjusted CCA

What assets were included?

Only tangible assets included.

Not public Assets associated with onshore system, interconnectors and Inch entry point

Assets included in financial statements

Regasification, storage and transportation facilities that entered into service by 31/12/2001.

All transportation assets in existence at time



Belg

ium

Fra

nce

Ire

lan

d

Italy

Spain

UK

Were existing assets revalued to determine the initial value?

Value based on company asset inventory

Not public Adjustment to reallocate value of an EU subsidy, to reflect CER’s judgement on appropriate allocation of common buildings across licensed activities; and to adjust for value of telecommunications business. Regulator also used different asset lives to company which would have resulted in a difference in the asset values used.

Adjustment made to net off value associated with government subsidies and accumulated economic-technical amortisation.

Ministry set value - methodology not public

Current cost asset valuation adjusted by MAR

Was there an adjustment for inflation?

MEA valuation includes, by definition, inflation adjustment (i.e. current replacement cost of assets)

Not public The historic value of assets were inflated by the CPI. The CER does not explicitly discuss why an inflation adjustment was needed but do emphasise that this particular index was chosen to ensure that asset values reflect the real cost increases experienced by BGT.

Historic asset values inflated using a gross fixed investment deflator. Reason for inflation adjustment not discussed by regulator – specified in guidelines.

Ministry set value - methodology not public

Not discussed – market value

approach takes some account of inflation

adjustment indirectly plus asset values

used were calculated on current cost basis

Table 7: Calculation of the opening value of the regulatory asset base Source: Country studies



4.3 ROLLING FORWARD THE ASSET BASE

In this section we consider how regulators set the allowed investment and depreciation levels in the RAB when assessing forward looking tariffs. We also comment on the price indices used to roll the asset value forward from year to year. We only consider countries which use an index approach to setting the RAB (including the non-standard index approach used in Italy and Spain).

4.3.1 Treatment of new investment

As shown in Table 8, in Belgium, France, Ireland and the UK the RAB for year n is equal to the closing value of the RAB in year n-1 plus expected investment and less expected depreciation. The RAB is also rolled forward by an inflation index. Variation arises, however, in the valuation of the closing RAB in year n-1 by country. In Belgium and France the closing value is updated to reflect actual investment and actual deprecation during year n-1. That is, expected investment is only retained in the RAB for one year. In Ireland and the UK during the regulatory period the closing value of the RAB in year n-1 countries to include historic expected investment and depreciation for earlier years in that same period (and actual for previous regulatory periods). In all cases it is the book value of the investment, net of depreciation, which is included in the RAB - whether expected or actual.

There is variation in the types of assets which are included in the roll-forward of the RAB and, in some cases, in the way in which capital expenditure is defined. Clear definitions are not generally provided by regulators, however, although the general practice appears to be that the regulator will allow expected capital expenditure that it deems to be reasonable or required for the forthcoming period. There is generally a process of negotiation between the company(ies) and the regulator as to what that reasonable level is but public details on such negotiations are generally not available. The one exception is the UK where Ofgem publishes details on the process involved. The steps of the process are as follows.

•

•

Transco provides a business plan for the five-year period, including forecasts of required net new investment for assumed service standard requirements. In the 2001 review (for the period 2002 to 2007) a distinction was made between investment to meet minimum statutory obligations, investment to improve network resilience, and investment to increase summer flexibility. Replacement expenditure was also treated as a separate item in the forecasts. Detailed costing, work load and output information is provided for some individual projects, potentially at the request of Ofgem.

Ofgem reviews the forecasts, with advice from consultants, to determine whether the level of proposed investment is consistent with the expected efficient cost of delivering required outputs (with different scenarios reflecting variation in supply/demand assumptions). Forecasts are made for individual components of the investment programme.



• Ofgem also compares Transco’s forecast levels of investment to historical investment levels to determine and assess whether significant changes are warranted.

•

•

…

…

Revised forecasts for capital investment are published by the regulator, based on adjustments proposed by consultants, and Transco provides comments on the revised numbers. Ofgem may also seek, at this point, further evidence and detail on individual investment projects.

The final price control is set including the regulator’s revised forecast for new investment, which may be different to the draft proposals.

There is therefore a process of consultation on the required level of net new investment, with Transco and the regulator (with support from experts) debating the appropriate level of investment given required outputs. The negotiation in 2001 resulted in a 22% difference between Transco’s proposed investment programme (£2,985m for the period 2002 to 2007) and the level of investment allowed by the regulator in the price cap determination (£,2,331m).

As noted earlier new investment is treated differently in Italy and Spain. Details of the methodologies used can be found in the country studies and are summarised here.

In Italy the book value of new investment, net of depreciation, is added to the calculated initial value of the asset base to determine allowed revenues for the year. The initial asset value, and new investment since the initial asset value was set, are also rolled forward by inflation to the current year. For allowed revenues in year n, the depreciation charge and allowed return on actual investment from 2001 to n-1 (inflated to year n prices) is included in the allowed revenue calculation and the expected depreciation charge and allowed return on investment for year n is included.

In Spain, the allowed revenue in year n is split into a number of different components - the allowed revenue associated with the initial assets at 31st December 2001, the allowed revenue associated with new investment undertaken between 31st December 2001 and year n-1, and the allowed revenue associated with expected investment in year n. The allowed revenue for assets which have come into operation since 31st December 2001 is calculated, in the year that the assets become operational, as the value of the depreciation charge plus a return earned on the asset value. All elements of the allowed revenue calculation are adjusted by inflation each year, giving a real allowed revenue value on which tariff calculations are based.

Fundamentally both approaches have the same economic effect – with the value of the total asset base (historic assets and new assets) being reduced by depreciation over time and increased by new investment – but the presentation of the information and the process involved is different.

4.3.2 Depreciation

All regulators use a straight-line depreciation rule when rolling forward the asset base. The asset life assumptions are detailed in Table 8 . There is some variation



across countries but the main asset groups such as pipelines appear to be treated consistently by most regulators.

Few regulators differentiate between assets which existed at the time that the initial value of the RAB was set and assets which have come into operation since. The exceptions are Belgium and the UK. In Belgium different asset rules are used for assets in the initial value but these are not public. In the UK different asset life assumptions are made for existing assets and new investments, as noted in Table 8.

Similarly, regulators do not generally discuss the write-off of historical assets in the RAB. The two exceptions to this are Belgium and Spain.

…

…

In Belgium if the value of particular assets that are in use falls below 20% of the MEA value the depreciation rate is reduced to 0% and hence full write-off does not arise.

In Spain, assets which have reached the end of their economic life and which have closed down are removed from the allowed revenue calculation. However, assets which have reached the end of their economic life but which are still in operation are retained in the calculation of allowed revenues, with all of the operating expenditure included and 50% of the allowed return on capital investment.

In all other countries it appears that standard depreciation rules are applied to historic assets and hence these would be expected to be written-off at the end of their assumed economic life.

Schemes such as those used in Belgium and Spain may be in place to encourage efficient investment decisions by the regulated company. Specifically the scheme may be designed to encourage shareholders and managers to make efficient choices between continuing to maintain existing assets or replacing them with new assets when the assets can be run for longer than the assumed economic life. The merits of such schemes need to be considered in the context of the overall regulatory regime that is in place and, in particular, in relation to existing incentive arrangements. For example, in a cost-plus regime there may be an expectation that companies will have an incentive to overinvest and choose replacement over operating and maintenance (O&M) options. The decision to not write-off existing assets in the RAB may counter this incentive somewhat in this regime. In contrast, in an incentive regime, such as a five-year price control, companies are provided with separate incentives to reduce costs, alongside specific investment incentives. The combination of these incentives might be expected to encourage O&M at the margin but the overall cost reduction incentive may encourage replacement if this is the cost minimising option. A decision to allow companies to continue to earn a return on assets that are older than their assumed economic life should therefore be evaluated in the context of the overall regulatory regime. In particular such a scheme should be assessed in the context of whether or not companies are expected to have a strong incentive under the existing regime to replace assets rather than maintain them even if this is not the cost minimising choice.



4.3.3 Inflation indices

All countries except Belgium roll the asset value forward by an inflation index. The Belgian regulator has not provided an explanation as to why an inflation index is not used, although the methodology is consistent with that used in other sectors. The index used in Italy is an average of the consumer price index and the industrial price index plus an efficiency factor. In all other countries a national consumer price index is used to roll forward the asset value (in Ireland the Harmonised Index of Consumer Prices is used).



Belg

ium

Fra

nce

Ire

lan

d

Italy

Spain

UK

How is the initial value rolled forward for theregulatory period?

Add in budgeted additions, withdrawals and depreciation for next year. No adjustment for inflation.

Book value of additions and withdrawals are added to the opening value.

Book value of expected capital investment, less expected withdrawals and depreciation added to opening value. All asset values rolled forward by Irish Harmonised Consumer Price Index.

Annual allowed revenue calculated as the initial value of the asset base rolled forward by inflation plus the value of investments undertaken since 2001 (in current prices) net of deprecation.

Annual allowed revenue calculated as the allowed revenue associated with the initial assets at 31st December 2001 and the allowed revenue associated with investments undertaken since then. The allowed revenue for new investment is calculated as the deprecation charge plus the return on the investment cost, rolled forward by inflation.

Current cost value of expected new investment, withdrawals and depreciation on new investment and MAR-adjusted depreciation on pre-1992 assets. Also rolled forward by inflation.

What types of new investments are included in the RAB?

Only tangible fixed assets included. Only costs deemed reasonable by CREG included.

All assets Capital investments that are not subject to a regulatory consent requirement included. Replacement expenditure not included. Adjustments made to BGT’s forecast capital expenditure.

Net fixed assets based on formulas set by AEG, assuming the net working capital to be zero.

All fixed assets for regasification, storage and transportation facilities

Previously all capital expenditure and replacement expenditure. Only 50% of replacement expenditure since 2001 review.



Belg

ium

Fra

nce

Ire

lan

d

Italy

Spain

UK

Are assets in the course of construction included?

Not discussed Assets added when enter into service or are commissioned.

Yes – e.g. second interconnectors under construction. As discussed, separate depreciation rule for these assets.

Only assets which are in operation are included.

Companies may ask the Directorate General for Energy Policy and Mines to include them if they meet a set of pre-specified requirements (see country study).

Not discussed by Ofgem

What depreciation rule is used – e.g. Straight-line/linear

Straight-line rule Straight line depreciation

Straight line depreciation standard. Some variation for assets in the course of construction (underutilised capacity)

Straight line Straight-line, based on the assumed useful life (as set by the Ministry rules)

In the 2001 price review Ofgem introduced straight-line on all assets. For the previous period the MMC (1997) had used MAR-adjusted deprecation for pre-1992 assets and straight line depreciation on new assets.



Belg

ium

Fra

nce

Ire

lan

d

Italy

Spain

UK

What are the assumed asset lives?

The assumed asset lives for depreciation purposes are: Industrial buildings – 33 years Administrative buildings – 50 years Pipelines – 50 years Metering, pressure reduction and compression devices – 33 years Storage installation – 33 years Teletransmission and optical fibres – 10 years Equipment and furniture – 10 years Rolling stock – 5 years

Examples: Pipes – 50 years Compression stations – 30 years Other technical installations – 10 years

Asset lives based on engineering advice: Pipelines – 50 years (BGT proposed 40 years) Compressor stations – 25 years (BGT proposed 20 years) Above Ground Installations – 40 years (as proposed by BGT) IT equipment – 5 years No other assets mentioned by CER

Pipelines - 40 years Compressor stations - 20 years Buildings - 50 years Other fixed assets - 10 years

For gas pipelines business: Pipelines – 30 years Compression stations – 20 years Regulation and measurement facilities – 30 years

In the 2001 price review Ofgem made the following assumptions about NGT’s transportation assets: • •

existing assets - 28 years

new investments - 45 years

In the 1997 price control the MMC, and Ofgem, made the following assumption about the NTS assets: Pipelines - 48 years Above ground installations - 24 years Compressors - 35 years Terminals - 30 years Services - 35 years Meters - 20 years Plant and machinery - 20 years Storage facilities - 40 years Telecommunications - 10 years Vehicles - 6 years Other - 5 years



Belg

ium

Fra

nce

Ire

lan

d

Italy

Spain

UK

What assumptions were made about the writing-off of existing assets?

Historical assets (pre 31/12/2002) depreciated at the rates previously set by the Control Committee for Electricity and Gas (details not available from CREG). When residual value of assets (historic and new) falls below a minimum of 20% of the MEA value the deprecation rate drops to zero

Not public None specified – except for standard depreciation rules

None specified – except for standard depreciation rules

Assets which have reached the end of their economic life and which have closed down are removed from the allowed revenue calculation. However, assets which have reached the end of their economic life but which are still in operation are retained in the calculation of allowed revenues, with all of the operating expenditure included and 50% of the allowed return on capital investment.

MAR-adjusted depreciation was previously used on pre-1992 assets in RAB – consistency with MAR adjusted valuation of these assets in the RAB. All assets are now depreciated on straight-line basis, presumably reflecting an assumption that pre-1992 assets are now largely depreciated but also to simplify the system.



Belg

ium

Fra

nce

Ire

lan

d

Italy

Spain

UK

What inflation index is used to roll the RAB forward?

None - annual adjustment does not include update by inflation.

An inflation index is used and is assumed to be a consumer price index.

The Harmonised Consumer Price Index is used. This is different to the Irish CPI used to calculate initial value of the RAB.

The regulator states that a standard ‘inflation’ index is used and this is assumed to be a consumer price index. This is different to the index used to determined the initial asset value.

The allowed revenue associated with the initial assets and the allowed revenue associated with new investments undertaken since 31st December 2001 are rolled forward to the current year by an inflation index which is equal to an average of the consumer price index and the industrial price index plus an efficiency factor.

The retail price index (RPI) is used.

Table 8: Depreciation and investment allowances in the regulatory asset base Source: Country studies



4.4 ROLLING FORWARD THE RAB FOR OVERSPEND AND UNDERSPEND

In this section we consider how regulators set the revised opening value for the RAB at the start of each regulatory period. The main questions here are whether:

• • •

•

•

the regulator replaces allowed investment with actual investment in the RAB;

if so, when that replacement occurs; and

whether all actual investment is included or whether a used and useful test is applied?

Most countries use actual investment in previous years, and expected investment in the next year, as the basis for setting tariffs. In the case of countries that use an index approach and review tariffs annually (Belgium and France) the expected investment in the previous year is replaced by actual investment when tariffs are revised. For example:

the opening RAB for Fluxys (the Belgian TSO) in 2003 was set equal to the opening value in 2002 plus actual 2002 investment and less actual 2002 depreciation; and

in France the opening value of the RAB for each review period is equal to the value of the RAB in the previous period revalued by inflation of assets from their entry into service (inflated book values), depreciation, the commissioning of new assets (book values) and the retirement of old assets (book values).

In Italy and Spain annual allowed revenues are also calculated based on actual investment in the previous year. There is no discussion, as yet, of how the initial value set for the current regulatory period (the first one in both countries) may be rolled forward when the tariff setting methodology is next reviewed.

Only Ireland and the UK review tariffs after more than one year. Ireland has not yet developed a methodology for these issues because tariffs have only been set for one period. In the UK, the RAB at the start of a new regulatory period is set equal to the RAB at the start of the previous period rolled forward by actual investment, actual depreciation and inflation over the period. In the past the level of investment has been lower than that allowed by the regulator and, hence, this adjustment has resulted in an initial step-change reduction in the value of the RAB. However, in the current regulatory period Transco, the UK gas TSO, has expenditure levels which are significantly above the level allowed by the regulator in the previous review. It is not clear whether these higher levels will be included in the RAB going forward and this is expected to be a central issue of debate at the next review.



5 Calculating the WACC

The calculation of capital costs requires the regulator to determine the allowed return earned on the RAB. That is, the regulator must form an opinion on the cost of capital which the company is allowed to earn under the tariff restraint. Variation in the allowed cost of capital across European countries will therefore result in differences in the tariff charges. This may distort decisions about gas transit across countries and hence consistency in the methodologies used to calculate the cost of capital, and the value used, may be important.

Table 10 summarises the methodologies used by regulators to calculate the cost of capital. Details of the values assigned to individual components of the calculation of the weighted cost of capital (WACC) are also provided.

5.1 COST OF CAPITAL METHODOLOGY

Of those countries that make their methodology public, all but Spain calculate the cost of capital as a weighted average of the cost of equity and the cost of debt. The pre-tax WACC is calculated as:

(1-gearing)*cost of equity+(gearing)*(1-marginal tax rate)*cost of debt

Spain set the value equal to the annual average of a 10-year interest rate (similar to the risk free rate) plus 1.5%. We consider each element of the WACC calculation in turn.

If DTe were to use a weighted average methodology this would be consistent with the approach adopted by other gas regulators. This methodology is also used by regulators in a wide range of other sectors including electricity distribution and water and sewerage services. Regulators appear to use this methodology because it is recommended in reports from consultants and academics and/or because it is consistent with the approach adopted by other regulators.

5.2 COST OF EQUITY

The Capital Asset Pricing Model (CAPM) is the methodology used to calculate the cost of equity by all but one of the countries that use a weighted average calculation for the cost of capital. The methodology used in Germany for the cost of equity is not publicly available. With the CAPM methodology the cost of equity is calculated as:

Cost of equity=risk free rate + beta * equity risk premium

Again, if DTe were to use a CAPM methodology to calculate a cost of capital for GTS this would be consistent with practice elsewhere. The numerical values of each of the parameters in the equation would need to be calculated for the specific company however – using proxy comparator values only where data is not available – as it is not clear that the actual values need be consistent across countries. This is a matter that DTe may wish to review in more detail.

Calculating the WACC


5.2.1 Risk free rate

Not surprisingly the value of the risk free rate varies by country, from 2.5% (real) in Ireland to 5% in Belgium. The variation is partly explained by the fact that estimates were made at different time periods and because of differences in debt markets. Where the methodology for calculating the risk free rate is publicly available is appears to be based on an average over a medium- to long-term period of returns on a government bond.

5.2.2 Equity risk premium

The value used for the equity risk premium also varies slightly by country, from 3.5% in the UK and Belgium to up to 5% in Austria and Ireland. Variation in this factor would arise from differences in the risk-free rate and differences in the relationship between stock market performance and this risk-free rate across countries.

5.2.3 Equity beta

There is also some variation in the equity beta calculated for gas transmission operators. A value of 1 is used in Belgium and the UK (implying that the gas transmission company is assumed to be as risky as the national stock market). A slightly lower value of 0.9 is used in Ireland, while a range of significantly lower values (between 0.28 and 0.4) were considered for Austria.

5.3 COST OF DEBT

In Austria, Ireland and the UK the cost of debt is calculated as:

Risk free rate+debt premium

The resulting values ranged from 3.9% in Ireland, to 4.5% in Austria and the UK. In Belgium and Germany the cost of debt is calculated as the actual interest on the company’s own debt and the values are not publicly available.

DTe would need to review whether it has a legal duty to ensure that company-specific debt is financed through the regulatory control and whether, independent of the legal duty, such an approach would be desirable. This is a subject that is beyond the scope of this report but may warrant further analysis by DTe.

5.4 GEARING

Only five countries were able to provide details on the gearing level assumed in the calculation of the WACC. Belgium and Germany use the company’s actual gearing ratio in the calculation while Austria, Ireland and the UK use an assumed ratio which, at least in the case of Ireland and UK, is expected to reflect a regulatory assumption that the company makes optimal financing decisions. The assumed values are 58% (Austria), 55% (Ireland) and 65% (UK).



5.5 INFLATION AND TAXATION ADJUSTMENTS

In general regulators use a real pre-tax value for the WACC. The tax adjustment is based on the corporation tax rate faced by the individual company which can vary significantly across countries. The resulting estimates of the calculated pre-tax real WACC are provided in Table 9 for ease of reference. The value in Austria is nominal as a historic cost asset value is used.

Country Real pre-tax WACC value

Austria 6.5% (Nominal)

Belgium 7% (approx, but varies by company according to company-specific cost of debt)

France 7.75% for assets in operation on 1 January 2004 9% for new investments

Ireland 5.74%

Italy 7.94%

UK 6% to 6.25%

Gasunie proposal

8.2%

Table 9: WACC values




Au

stria

Belg

ium

Fra

nce

Ge

rma

ny

Ire

lan

d

Italy

Spain

UK

What methodology is used to calculate the WACC?

Weighted sum of cost of

equity and cost of debt

Weighted sum of cost of equity and cost of debt

Not public Weighted sum of cost

of equity and cost of debt

Weighted sum of cost of equity

and cost of debt

Weighted sum of cost

of equity and cost of debt – details of parameters

used not public

Rate of remuneration

is equal to the annual average of

10-year interest rate plus 1.5%. Specified in Ministerial

Order.

Weighted sum of cost of equity and

cost of debt

What methodology is used to calculate the cost of equity?

CAPM - 10.1% pre-tax

CAPM – approximately 8.7% post-tax

Not public No methodology provided –

value of 7.8% pre-tax

in Association Agreement.

CAPM – 7% real pre-tax.

CAPM - details of

underlying parameters not available

Not relevant CAPM – 8.9% pre-tax in 2001

price review

Why was this methodology chosen?

Based on consultancy

report provided by academic

expert

Consistent with methodology

used in electricity sector

Not public Appears to be based on consultancy

study but details not stated in

Agreement

Widely used and generally understood

Not available

Not relevant Consistent with that used by

other regulators and Competition

Commission



Au

stria

Belg

ium

Fra

nce

Ge

rma

ny

Ire

lan

d

Italy

Spain

UK

What is the value of the risk free rate?

3.94% - forward-looking

measure based on the current rate of

Austrian Government bonds with a remaining life of 10 years

Average (arithmetic) return on 10

years government

bonds issued in previous year.

Equal to 5.112% for 2003 tariff.

Not public Not available

2.5% (real) – nominal rate of

4.5% suggested by NERA, based on average maturity on

long-term bond in Eurozone

market.

Not available

Not relevant 2.75% - average redemption yield

on range of bonds, with an

upward adjustment from the actual rate of

2.5% for uncertainty of future yields

What value was used for the equity risk premium?

Range of 4.5% to 5.%,

with suggested; value of 5% used, based

on comparison of risk free rate and

returns in the equity market.

Difference between risk free rate and return earned by a basket of

shares on Belgian market. Set at 3.5% for

2003 tariffs


5% - NERA suggest range of 5-7% based

on historic estimates,

survey evidence and previous CER

decisions.

Not available

Not relevant 3.5% - based on assessment of

historical returns and surveys of institutional and investor opinion



Au

stria

Belg

ium

Fra

nce

Ge

rma

ny

Ire

lan

d

Italy

Spain

UK

What value was used for the asset beta?

Not available Not available Not public Not available

0.4 – NERA suggest range of 0.45 to 0.55.

Based on comparison with British Gas’s asset

beta and range allowed by Australian regulators.

Not available

Not relevant Range of 0.4 to 0.6 suggested –

based on evidence for

British Gas Group and an

assessment of implications for the regulated

business.

What value was used for the equity beta?

Range of 0.28 to 0.33

proposed by one report. Alternative

reports suggest a

range of 0.3 to 0.37 and

another suggests a

value of 0.4

Value of 1 used for 2003 tariffs


0.9 – asset beta adjusted

by gearing assumption

Not available

Not relevant 1.0 used in final calculations –reflects asset

beta and gearing of 60%.



Au

stria

Belg

ium

Fra

nce

Ge

rma

ny

Ire

lan

d

Italy

Spain

UK

What gearing level was used? (actual or efficient?)

Assumed to be 58%, based on

reports from various

consultants

Ratio of equity fund to

borrowed fund was 33:67

Not public Actual levels up to a

maximum of 40% equity

55% – assumed

optimal level. Based on average of

market gearing ratios for

comparator companies.

Not available

Not relevant 62.5% - assumed optimal level.

Consistent with assumption made

for electricity transmission

company.

How was the cost of debt calculated?

Risk free rate plus debt

premium -4.54% pre-tax

Actual interest on debt of the

company.

Not public Actual company

cost of debt used –

values not available

Real risk free rate plus debt

premium – 3.9%

Not available

Not relevant Risk free rate plus debt

premium – 4.25% to 4.65%



Au

stria

Belg

ium

Fra

nce

Ge

rma

ny

Ire

lan

d

Italy

Spain

UK

What debt premium was used?

60 basis points, based

on consultancy

report

0.7% (70 basis points) used for

2003 tariffs


1.4% - NERA suggest

premium of 137.5 basis

points, based on evidence of

comparator bonds and

assumption that BGE’s credit rating status

must be retained

Not available

Not relevant 1.5% to 1.9% - based on data for yield on corporate and utility bonds

over the last year, reflecting

premium required to retain

Transco’s investment grade credit rating on its

debt

What adjustment was made for tax?

A tax shield of 34% was used

Cost of equity adjusted to pre-tax basis using tax rate paid by

Fluxys

Not public Not clear in Association Agreement

Tax shield of 12.5% used.

Not available

Not relevant Tax shield of 43% used



Au

stria

Belg

ium

Fra

nce

Ge

rma

ny

Ire

lan

d

Italy

Spain

UK

What was the value of the WACC used?

6.5% pre-tax - only applied to

interest bearing capital

Approximately 7% pre-tax, but

varies by company

according to company-

specific cost of debt

Real pre-tax value -

7.75% for assets in

operation on 1 January

2004; 9% for new investments

Not available

Real pre-tax of 5.74%. Real

post-tax value is 5%.

7.94% real Varies depending on value of

10-year interest rate.

Real pre-tax range of 6% to

6.25%

Table 10: Calculation of the WACC




6 Key findings and implications for The Netherlands

The previous sections provided an overview of the main approaches which are used by regulators to set tariffs levels and, in particular, to calculate capital costs. The lessons learned from this assessment are used here to compare the methodology used for GTS to-date with that adopted by other countries with good regulatory practice. The section concludes with a review of the case for, or against, changing the methodology used in the Netherlands given this comparison.

The comparison between the Netherlands system and that used in other countries is focused on the four issues that DTe has indicated are of most interest to it, namely:

• • • •

the methodology used to calculate the opening value of the RAB;

the inflation index used to roll the RAB forward;

the depreciation rule used; and

the value of the WACC (i.e. the allowed return on the RAB).

We first consider the similarities and differences across the regulatory regimes that are in place as these may influence the extent to which comparisons across countries are relevant.

6.1 GENERAL REGULATORY FRAMEWORK

All countries except Germany have a formal regulatory regime, with an established regulatory agency that works either independently or operates within or alongside central government. Other than in the UK, the regulatory regimes and the regulatory agencies have only been established since 2000 and hence several issues relating to the rolling forward of asset values and the treatment of assets that have reached the end of their economic lives have not been considered yet. The institutional framework in the Netherlands is therefore consistent with the frameworks in other countries.

Most countries use a cost-plus methodology to set allowed revenues, although a price cap mechanism is used in Ireland and the UK. Furthermore, all countries reviewed, except Ireland and the UK, review tariffs annually and in particular use actual investment levels to calculate allowed revenues. All countries consider operating expenditure, the value of assets that existed when the regulatory regime was introduced, capital investment and depreciation when assessing the required level of allowed revenues and hence tariffs.

In general the regulatory regimes in Ireland, Italy, Spain and the UK are expected to reflect good regulatory practice. The self-regulation system in Germany is under review, indicating that this is not considered a satisfactory regime. The annual tariff adjustments in Austria and Belgium are expected to be very cumbersome and bureaucratic and indeed in Belgium there are on-going

Key findings and implications for The Netherlands


discussions about whether or not to move to a five-year system. Across the four preferable models, the Ireland and UK regimes are expected to have better incentives as adjustments for allowed costs are not made at the end of each year.

The methodology used in the Netherlands - ex-ante cost plus methodology with tariffs reviewed every four year - is therefore consistent with the methodology used by other regulators and the efficiency incentives provided are consistent with good regulatory practice.

6.2 CALCULATION OF THE RAB

We compare the approach considered by DTe for calculating GTS’s RAB in 2002 to that used by other regulators and provide a preliminary assessment as to whether such an approach is consistent with that used by other regulators.

6.2.1 General framework

We focus in this section on the general methodology used to calculate the RAB. We understand that in 2002 DTe considered using an index approach to calculate the RAB for GTS. As shown in Table 11 this is the most prevalent methodology used across regulators and the book value approach is only observed in Austria (where tariffs are adjusted annually) and in Germany under a self-regulation Association Agreement. We note, however, that the index approach used in Italy and Spain is non-standard.

Book value Index approach

Price cap regulation Ireland UK

Annual cost plus Austria Belgium France Italy*

Spain*

Cost plus for longer regulatory period

Netherlands

Self regulation Germany

Table 11: Methodology for calculating the RAB given regulatory regime

Note: * Non-standard index approach – The initial asset value is not rolled forward by net new investment each year. Instead, the initial value is included as a separate element in the allowed revenue calculation in each year of a four-year period, and the return on net new investments undertaken since the start of the period are included separately in the annual revenue calculation. All elements of the allowed revenue calculation are restated in real terms (ie. rolled forward by inflation) at each annual tariff review.

Source: Frontier Economics based on country studies

Good regulatory practice also suggests that the index approach is likely to be appropriate. This is because, as noted by a number of regulators, it allows the asset value to move towards the economic replacement value of assets over time,



it can be used to provide capital efficiency incentives to the company and it is consistency with the methodology used in other sectors. Furthermore, it is less susceptible to fluctuations arising from accounting revaluations than the book value approach.

An index approach for calculating a RAB for GTS is consistent with the methodology used by other regulators and with good regulatory practice.

6.2.2 Calculation of the opening value of the RAB

In 2002, DTe estimated the initial value of GTS’s RAB using the historic cost book value of the assets. An adjustment was made for difference in the assumptions that the regulator made about depreciation rates relative to those used in the company’s accounts. No adjustment was made for inflation.

Accounting approach

As shown in Table 12 Ireland and Italy base the initial value of the RAB on the historic book value of assets, but an adjustment is made for inflation. Belgium used a replacement cost methodology and the UK used a market value approach. The methodologies used in France and Spain are not publicly available.

We have not been able to obtain explanations from all regulators as to why the book value or market value approach is adopted. Where explanations have been given the choice tends to reflect the regulator’s objectives, an assessment of the preferred degree of volatility in revenues going forward (or more generally distributional concerns) and the need for simplicity in a regime (particularly if tariffs are adjusted annually) rather than being based on a clear set of economic guidelines. Regulators that use an inflated historic cost approach or a MEA valuation also emphasise that this is preferred as it provides a proxy estimate of the current value of the assets.

Taken together this analysis suggests that, assuming an index approach is used, there is no clearly preferred methodology for calculating the initial value of the RAB and no clear signal as to which is the most appropriate one to use. There is thus no clear lesson, from the cross-country comparison, on what methodology is appropriate for calculating the initial value of GTS’s RAB.

Economic principles indicate that the RAB should be set to ensure that investment is recovered over the lifetime of the assets. Different RAB profiles can deliver this outcome and the appropriate profile will partly depend on how investment has been recovered historically (i.e. whether the investment has been just-recovered, under-recovered or over-recovered). That is, the RAB should tend to the current cost value of assets in the long-run (as historic assets are written-off and replaced with new investments that are valued on a current cost basis) but the path taken to reach this point can vary depending on the extent to which the regulator wishes to take account of intergenerational equity issues.

This suggests that DTe and Minez may wish to consider a range of alternative methodologies and analyse the implications of these for consumer prices and shareholder returns over time. Regulatory objectives relating to the appropriate trade-off between consumer interests and shareholder interests in the short-term and the long-term will also need to be considered. Finally, the analysis of the



appropriate value to set for the opening value of the RAB should be considered alongside other elements of the ‘tariff package’ including the methodology for rolling-forward the RAB, the allowed WACC and efficiency assumptions.

Adjusted Indexed historic cost

Replacement cost value

Market value

Countries Ireland Italy

Belgium UK

Rationale Objective. Provides stable revenue path.

Close to replacement cost value.

Reflects economic value of assets in long run – efficient prices

Shareholders earn return on their

investment only; consumers pay lower prices than would be the case with current

cost valuation of assets

Table 12: Methodology for calculating the initial value

Source: Frontier Economic based on country studies

Inflation index for the initial value

Italy and Ireland inflated the historic cost of assets in the initial value. The Irish regulator used the Irish consumer price index for this purpose and the Italian regulator used a gross fixed investment deflator.

The regulators have not provided detailed explanations as to why this was the case and it has not generally been a point of dispute or debate in regulatory settlements. Indeed it appears to be treated as an accepted standard methodology which is used to ensure that the initial value is close to the replacement cost value of the assets.

The indexation of the historic cost of assets is not necessarily consistent with good regulatory practice. Whether or not indexation is desirable will depend on whether shareholders have already been compensated, through tariffs in other years, for the costs of inflation. If this has been the case then using an indexed historic cost initial value may involve double-counting of this cost. If, however, it is deemed desirable to switch to an indexed asset base and real return (from a nominal asset base and inflation adjusted return) it is important that the inflation factor is well chosen. The use of the CPI to revalue the historic cost of the assets is likely to significantly over-estimate the replacement costs of the assets if the actual rate of inflation of the equipment required to build a gas network has been much lower – indeed this is likely to be the case.

It is not clear, from good regulatory practice, whether an indexed approach is preferable to the standard historic cost approach. However, DTe and Minez may wish to calculate an indexed historic cost of assets for GTS using a range of alternative inflation indices. The impact of this change on consumer prices should be considered for alternative assumptions about the WACC and the rolling forward of the RAB.



Other adjus ments to the historic cost of assets t

As discussed in section 4.2 some regulators adjusted the values provided to them by the company before finalising the initial value of the RAB. These adjustments tended to relate to the need to deal with the value of EU subsidies paid or to ensure that the value related to the regulated transportation business only. Such valuations are not expected to be very relevant for GTS.

In addition, the Irish regulator adjusted the book value of assets to reflect different assumptions about appropriate asset lives. The actual size of the change in the value is not available but the methodology used appears to be consistent with that used to adjust GTS’s historic cost asset value for different depreciation assumptions.

The adjustment made to GTS’s asset lives in the calculation of the initial value is consistent with the methodology adopted by other regulators.

6.2.3 Rolling forward of the RAB

All regulators roll forward the initial value of the RAB by expected investment minus expected withdrawals and expected depreciation. An inflation adjustment is also used (except in Belgium). As discussed in section 4.4 there is variation in the timing at which expected investment is then replaced with actual investment to determine a new opening value of the RAB for the next regulatory period. In the majority of countries, except UK and Ireland, this happens at the end of each tariff year and hence efficiency incentives are expected to be limited.

Furthermore, most regulators use a consumer price index to roll the RAB forward from its initial value (or in the case of Spain to roll allowed revenue forward). Italy and Belgium are the main exceptions. Italy uses an average of the consumer price index and the industrial price index plus an efficiency factor and Belgium does not roll forward by inflation at all.

It would be appropriate for GTS’s RAB to be rolled forward by an inflation index. Consumer price indices are generally used here but it is recommended that other options are also considered - such as the approach used in Italy. Finally, the choice of whether or not to use an index should be considered alongside the decision on whether to use a real or nominal WACC.

6.2.4 Depreciation

The asset life assumption for pipelines used by DTe when assessing the RAB for GTS in 2002 was 50 years, rather than the 20 year deprecation period assumed by the company. We consider here whether other regulators use similar asset life assumptions.

Straight line depreciation is the rule used by all regulators. As shown in Table 13 the asset life assumptions vary slightly be regulator but for the main asset categories – e.g. pipelines – they are not inconsistent with those assumed for the 2002 calculation of GTS’s RAB.

An asset life assumption of 50 years for pipelines is consistent with the assumption made by other regulators.



Country Depreciation rule Asset life assumptions

Belgium Straight line Industrial buildings – 33 years

Administrative buildings – 50 years

Pipelines – 50 years

Metering, pressure reduction and compression devices – 33 years

Storage installation – 33 years

Teletransmission and optical fibres – 10 years

Equipment and furniture – 10 years

Rolling stock – 5 years

France Straight line Examples:

Pipes – 50 years

Compression stations – 30 years

Other technical installations – 10 years

Ireland Straight line Pipelines – 50 years

Compressor stations – 25 years

Above ground installations – 40 years

IT equipment – 5 years

Italy Straight line Pipelines - 40 years

Compressor stations - 20 years

Buildings - 50 years

Other fixed assets - 10 years

Netherlands Straight line 50 years

Spain Straight line For gas pipelines business:

Pipelines – 30 years Compression stations – 20 years Regulation and measurement facilities – 30 years

UK Straight line (previously MAR

adjusted depreciation for pre-1992 assets)

Ofgem (2001): Existing assets – 28 years New investments – 45 years MMC (1997): Mains and services – 40 years Plant and machinery – 25 years Other – 5 years

Table 13: Depreciation rules

Source: Frontier Economics based on country comparisons



6.3 WACC

In 2002 DTe considered using a real pre-tax WACC of 8.2% for calculating the allowed return on GTS’s RAB. This value was provided by Gasunie and it is not clear what methodology was used to calculate it.

The majority of regulators use a CAPM model to calculate the cost of equity and calculate a weighted average cost of capital using this estimate, a gearing assumption and a cost of debt calculation. As discussed in section 5, there is significant variation in the values used. Further detailed analysis, which is beyond the scope of this report, would be required to determine which country – if any – provides the most suitable comparator for the Netherlands.

If the WACC for GTS were calculated based on the CAPM methodology the approach would be consistent with that used in other countries. A company-specific, calculation is needed however given the variation which exists across countries.

Country WACC value Methodology

Austria (2003) 6.5% real pre-tax CAPM

Belgium (2003) 7% approx real pre-tax; but varies by company according to

company-specific cost of debt

CAPM Company embedded

debt

France Real pre-tax value - 7.75% for assets in operation on 1

January 2004; 9% for new investments

Not public

Germany (on-going)

7.8% cost of equity Cost of debt varies by company

Cost of debt not public

Ireland (2003) 5.74% real pre-tax CAPM

Italy (2003) 7.94% real CAPM

Netherlands (2002)

8.2% real pre-tax Value proposed by Gasunie

Spain (2001) Average of 10-year interest rate plus 1.5%

Specified in Ministry Order

UK (2001) 6% to 6.25% real pre-tax CAPM

Table 14: WACC comparison

Source: Frontier Economics based on country comparisons



6.4 CONCLUSIONS ON THE DUTCH REGIME

The regulatory regime in the Netherlands is consistent with the good regulatory practice of using an ex-ante cost plus regime but with tariffs adjusted at intervals of four years.

An index approach to calculating the RAB for Gasunie would be consistent with the approach adopted with most other European regulators and with good regulatory practice.

The cross-country comparison has revealed that no consistent approach is used to calculate the initial value of the RAB. A review of alternative methodologies, based on the GTS’s own data, is therefore warranted to determine the implications for consumer prices and shareholder returns. Furthermore, when assessing the implications of an indexed historic cost value, alternative inflation indices should be considered.

When rolling forward the RAB it would be consistent with other regulators to use an inflation index, but again consideration should be given to the choice of index used.

Straight-line depreciation, with an asset life of 50 years for pipelines, also seems to be consistent with the methodology used by other regulators.

Finally, a WACC calculation using the CAPM to calculate the cost of equity would be consistent with the approach used in other countries.



Annexe 1: Glossary of key terms

…

…

…

…

…

…

…

Cost plus regulation – control is set on prices such that the allowed level of prices is set equal to actual operating and capital costs in the previous year. The level of costs allowed may reflect some assessment, by the regulator, of what the required level of efficient cost is. Companies have little incentive to reduce costs under this regime as the regulator allows all costs to be covered by the allowed prices and any reduction in costs will translate into a reduction in prices in the next year. Cost plus regulation for longer regulatory period – prices are based on the costs that are expected to arise over the course of the regulatory period. Efficiency incentives are determined by the length of the regulatory period and the treatment of outperformance by the regulator. Unlike the classical cost plus regulation described above, there is no presumption that outperformance over the period will be clawed back in full, and as a consequence the incentive properties of the regime can approximate to price cap regulation (defined below). Price cap regulation – a forward looking cap (upper bound) is set on the allowed annual change in prices for a fixed number of years (the regulatory period). The cap can be informed by a number of factors but is often calculated by estimating required annual expenditure for each year of the regulatory period, and as such resembles cost plus regulation for longer regulatory period described above. Discretion over the level of expenditure remains with the company who can make profits by delivering outputs at lower costs levels during the regulatory period (i.e. prices will not track actual costs during the period). This regime therefore provides companies with incentives to reduce costs during the control period.

Self regulation – companies agree between themselves the principles for setting prices/tariffs and monitor, perhaps with intervention from a Competition Authority or legal body, whether the principles are being met in practice.

Regulatory Asset Base (RAB) – the value of the capital assets held by a regulated business. The value is generally set or estimated by a regulator, based on information provided by the regulated company.

Book value approach – with this methodology the asset base of a company is set equal to the historic cost asset value in the company’s annual accounts each year.

Index value approach – with this methodology the annual asset base of a company is calculated as the opening value of the asset base plus net new investment each year since the opening value was set. For future years, expected or forecast new investment is included in the asset base. A number of different methodologies can be used to estimate the initial value (historic cost, modern equivalent asset value, current cost value, replacement value, market value).



…

…

…

…

…

…

Modern equivalent asset value (MEAV) – with this methodology capital assets are valued at a point of time on the basis of what it would cost, given current input prices and current technology, to replace them with alternative capital assets that would deliver the same level of outputs and quality of service.

Current cost value of assets - assets are valued at original purchase cost but the value on the books is uprated by general inflation every year. Replacement value of assets - assets are valued by inflating historic costs by an index specific to those assets or the industry considered. This is a variation on current cost value, but with a specific inflation index used rather than the general inflation index. Market value of assets – with this methodology capital assets are valued according to the price paid for them by equity shareholders on the stock market. The company assets are valued using stock market valuation (share-price times number of shares) plus net debt. The value reflects shareholder expectations of the return that they will earn from the company shares, which may be affected by expectations about the regulator’s future decisions.

Weighted average cost of capital (WACC) – the cost of capital of a company is calculated as the weighted sum of the cost of debt and the cost of equity. The weights used reflect the company’s gearing level (or an assumed optimal gearing level).

Capital Asset Pricing Model (CAPM) – this model is used to calculate a company’s cost of equity. The cost of equity is calculated as the risk free rate plus the equity beta multiplied by an equity risk premium under this model.



Annexe 2: Austria

All information in this report relates to research undertaken between October and December 2004. Changes implemented by regulatory agencies since then are not reflected in the country descriptions.

BACKGROUND ON GAS SECTOR

Name of gas transmission system (GTS) operator

Five companies - OMV, OÖFG, Gasnetz Steiermark, EVN, BEGAS – operate transmission lines across regions. In Austria transmission companies are responsible for providing connections between regional operators who supply the gas, and for transit across Austria.

Transmission lines are not defined with reference to some pressure level as is the case with distribution lines. All transmission lines are defined to be on level 1. The Gas law explicitly states which are the relevant transmission lines in Austria. Modifications or additions to the stock of transmission lines can be made by decree.

Ownership of GTS operator

The five GTS operators have a mixed public and private ownership. By law, AGGM AG which carries out independent Inter-TSO activities is 100% owned by OMV, an Austrian oil and gas conglomerate.

Is the GTS part of a wider corporate group? (Provide brief details)

All operators are part of wider groups that undertake other activities, including gas distribution. Except for OMV, all operators are also active on level 2 and 3, i.e. on the distribution level. OMV is also active in transit and a large part of its capacity is allocated to transit through private contracts.

Are there any proposed or planned changes to the industry or ownership structure?

No.

Table 15: Basic facts on GTS operator – Austria

Annexe 2: Austria


Scale of high pressure, medium and low pressure systems

Medium pressure > 6 Bar and Low pressure < 6 Bar define level 2 and 3 (i.e. distribution), respectively, Level 1 has no defined pressure level but is defined in terms of its functions (i.e. the linking of regional distribution networks). As stated above, the transmission lines are listed in the GWG II (the law) and amended in FLAVO (a decree).

Degree of interconnection with other gas systems (state countries)

Austria is a transit country, with transit volumes of about 24 billion cubic meters (bcm). and domestic import of 5.5 bcm. The gas flows are from Baumgarten to Italy and to Germany. Although there are contracts with Norway, the physical flow comes from Russia.

Are there any proposed or planned changes to the gas system (e.g. new interconnection agreements)?

The Nabucco Project: a pipeline to go from Turkey to Austria via Rumania and Bulgaria with exit points in each country to transport gas from the Caspian Sea. The new EU directive (the Acceleration Directive) envisages the possible exemption of regulatory control over new infrastructure investments which is what the investors are trying to achieve if they are to construct this pipeline.

The TAG expansion project: The Trans Austria Gasleitung (TAG) pipeline which transports Russian gas to Italy through Austria will be expanded. By 2008, the transport capacity will be increased by not less than 3.2 billion cubic metres per year, and the additional capacity will be allocated on a non-discriminatory basis under a procedure starting in September 2005.

The WAG expansion project: OMV signed a new contract with Gazexport, which authorises OMV to transport approximately 4.4 bcm of Russian natural gas, annually to 2027, from the Slovakian border near Baumgarten through Austria, to the German border near Überackern (Burghausen). A large expansion of the WAG system will be needed to achieve this, and OMV already plans to invest around EUR 260 million in the project.

Table 16: Technical information on gas sector - Austria

Annexe 2: Austria


BACKGROUND ON REGULATORY REGIME

Brief overview of history of GTS operator regulation

The regulatory system has been in place since 1.10.2002 when there was full market opening and a regulator was put in place. Before this there was partial market opening with negotiated third party access through an association agreement with the responsibility also relating to competition issues lying with the Ministry of Economics. The system by which access could be gained through the association agreement did not work well.

A large part of the transmission capacity is for transit. The capacity rights that go with transit are held by private companies and account for a large part of the transmission lines’ capacity. This capacity is not regulated.

Name of regulatory agency(ies)

Energie-Control GmbH (ECG) and Energie-Control Kommission (ECK), Vienna together form what is known as E-Control. The regulator really is the ECK, the decision making branch, not the ECG, the operative branch of the regulatory authority. However, the regulator in person is heading the ECG. He however merely proposes policy to the ECK.

Status of regulatory agency(ies)

The regulator is independent and is represented by the ECK (Energie Control Kommission a group of a few people which have to take unanimous decisions) who has decision making powers most importantly for setting tariffs. It is not bound by ministerial decisions and takes its decision on the basis of the GWG II (Gaswirtschaftsgesetz II), the law that provides the legal framework for the economic organisation of the sector and the Gassystemnutzungstarifverordnung, (GSNTVO 2004) the decree that implements the law (the GWG II) and the Energieregulierungsbehördengesetz, the law that stipulates how the regulatory framework is set and the regulatory authority is organised, its competencies and related matters.

The ECG is organised as a limited company acting as the operational unit of the ECK. However, the ECG might in certain matters be bound by ministerial decisions which lie outside the ambit of the ECK. The ECG will also be responsible for competition questions as regards primarily the supervision of legal and accounting unbundling as well as non-discrimination obligations imposed by the GWG II and the decree based on the GWG II.

Review of regulator’s functions with respect to prices and quality.

The law (GWG II, para.23) stipulates that the regulator sets prices for the transmission network which are implemented by decree. The principles underlying the setting of tariffs are that they should be cost reflective and efficient. The regulator is further allowed to impose productivity improvements. In terms of safety and thus quality of supply, by law the network operator has the duty to invest into the network to make the necessary extensions and to ensure that safety and environmental aspects is safeguarded.


ECK is the appeal body for decisions of the ECG (the decisions the ECG takes not in its competency as the operative branch of the ECK but the decisions it can take on its own); Verfassungsgerichtshof (constitutional court) and Verwaltungsgerichtshof (administrative court) for decisions the ECK has taken. Which of the courts is appealed to depends on the case at hand. If a decree is appealed against (e.g. the decree that set the tariffs),

Annexe 2: Austria


then the Verfassungsgerichtshof is the relevant court.

The ECK has the competency to make decisions – most importantly to set tariffs and in cases of refusal to grant access to networks. But the ECK is also the appeal body for the decisions the ECG has made, e.g. with respect to abuse proceedings. The decisions the ECK has made can be appealed against in front of the two courts which are supreme courts.


The ECK is an independent entity set up by the Austrian government, the Verfassungsgerichtshof and the Verwaltungsgerichtshof are supreme courts.

Description of any other legal or institutional influences on GTS operator

For environmental standards see question on regulator’s functions.

Are there any proposed changes to the regulatory institutions?

No.

Table 17: Regulatory institutions - Austria

Annexe 2: Austria


Overview of access arrangements

Transmission and distribution activities are both regulated but not transit transports which are determined by transport capacity rights. Most transmission capacity is used for transit and what is paid for transit is negotiated but the GWG II says that charges are to be cost reflective.

Tariffs for the transmission network are charged by summing the costs of all transmission operators – which are allowed costs – and then allocating the costs to all users on level 2 (as the customers of the transmission companies are the distribution companies) according to past values of off-take. On this basis a fixed annual sum is determined for each user on level 2. So in principle, users pay fixed annual fees.

For distribution there are also specific access conditions but for transmission only general conditions apply, e.g. the requirement not to discriminate between users, to deal with requests for transmission from national customers within a certain time frame, etc.

In the future, also transit capacity is to be regulated as the current EU legal framework requires this. However, Austria has not yet implemented the relevant directive into national law.

Description of form of restraint on prices

The E-control Kommission (ECK) decides by decree how much each transmission operator gets in terms of an annual fee. These fees can contain an element of change reflecting productivity improvements from one year to the next but this is currently not done.

The annual fees are derived by summing the allowed costs of all transmission operators and then allocating them on the basis of past off-take quantities. Note that this implies that the more efficient transmission operator gets more than his costs and the inefficient ones less. However, as costs are reassessed each year, there is little potential to gain from having costs below the average.

Frequency of price reviews/negotiations

The regulator can make costs assessments at any time and thus reset tariffs. As long as he does not do that, tariffs will be the same.

Coverage of the price restraint

National gas transmission costs allocated across companies

Methodology used to the set the price control

When assessing the costs of the transmission companies, operating costs are determined, as well as capital costs. Capital costs are taken to be the book value of non-interest bearing assets on which a WACC is applied (interest bearing assets are shareholdings and stocks) plus depreciation which is normal (linear) accounting depreciation on historic capital costs. The cost assessment is clearly retrospective, i.e. based on an assessment of actual costs in the past.

Structure of the control, e.g. revenue control, price control (tariff basket, average revenue yield), hybrid approach.

As mentioned above the sum of all costs of all transmission operators is allocated to customers on the basis of past off-take quantities and then charged as a fixed annual charge. Therefore, it could be called a revenue control for all transmission companies in aggregate.

Annexe 2: Austria


Does the regulator intervene on the charges/tariff structure?

No

Are there any proposed changes to the access arrangements and/or price restraints?

There are some changes currently in discussion, although no specific details are available yet.

Table 18: Regulatory regime - Austria

Annexe 2: Austria


CALCULATING THE REGULATORY ASSET BASE

Is a RAB used in the determination of price restraints?

There is a RAB in the sense that a capital value is determined to which the WACC is applied.

If a RAB is used, how is it valued?

Book value of assets at each review subtracting interest-bearing assets (see above).

Why was this valuation approach chosen?

Most of all pragmatism. In the absence of an incentive based regulation, the best the regulator considers he can do is to assess costs each year by visiting the companies and assessing their P&L accounts and their balance sheets and questioning certain cost items as well as ensuring that the WACC they get is not excessive.

What methodology is used to set the initial opening value of the RAV?

Value reset each year. The revaluation simply involves taking the new book value of gross assets (i.e. again using the HCA book value in the accounts minus the value of interest-bearing assets) and accounting depreciation (linear, as explained above). The book value will reflect the inflation for the year in question (i.e. 2003 book value will be in 2003 prices).

Why was this value chosen?

Simplicity and pragmatism – easiest option for annual reviews.

What is the starting point of the valuation?

Start of business year

What accounting approach is used to value the assets?

HCA

What assets are included in the calculation of the initial value?

Only non-interest bearing capital assets


No – book value taken from accounts

What assumptions are made about the writing-off of existing assets?

Not applicable

What principles, if any, were used to set the opening value?

None known

What practical assessment were involved in determining the opening value?

Value taken from accounts, with some high-level cross-check if TSO has revalued assets upward relative to previous year.

What depreciation rules are used?

According to HGB (commercial law) which is straight line depreciation.

What are the assumed asset lives used to calculate the depreciation charge?

Asset lives in companies’ accounts. Not changed by regulator.

Annexe 2: Austria


How is the initial value rolled forward for the regulatory period?

Not applicable with annual review

Are there any proposed changes to the methodology used to calculate the RAB?

No.

Table 19: Methodology used to calculate the RAB - Austria

Data is not available on the level of the RAB used to set tariffs.

Annexe 2: Austria


When calculating the RAB, how is capital expenditure defined?

To date, the regulator may have disallowed some costs, but this does not happen in any systematic way (i.e. there are no rules about specific types of costs – e.g. mains replacement – that are or are not allowed). It is just that when assessing costs, the regulator and the company practically negotiate over certain costs items. A transmission operator may want to be able to justify certain expenses but it is difficult for the regulator to come to a view as to how necessary these expenditures were as he does not undertake any benchmarking. The regulator believes however, that the threat of an annual cost assessment has already been quite effective in bringing costs down.

Is there any distinction in the regulatory treatment between new and replacement investment (provide details)?

No.

What is the history of disallowing investment?

See above.

Is there a used and useful test?

No.

What are the incentives for capital efficiency implied by the RAB updating?

None. This is not an incentive based system.

What is the treatment of capital work in progress?

See above.

Are there any proposed changes to the methodology used to include capital investment in the RAB?

No. In the long run, an incentive based system is aimed for but it is not clear how this would be implemented.

Table 20: Treatment of capital expenditure in the RAB - Austria

Annexe 2: Austria


CALCULATING THE WACC

What model is used to determine the cost of equity capital?

CAPM (WACC).

If the CAPM is used how is each building block calculated?

Generally, the choice for the value of each parameter is primarily based on one report by Bernhard Haider: “Gutachten zur Bestimmung eines angemessenen Kapitalkostensatzes für Gasnetzbetreiber in Österreich” (translated as “Assessment of an appropriate cost of capital for gas-net operators in Austria”), November 2003.

The risk free rate

The risk free rate is chosen based on forward-looking measures. The measure of the best estimate of expectations regarding the future value of the risk free as well as the rate of inflation rate is chosen to be the current rate of Austrian Government Bonds with a remaining life of 10 Years. The rate is 3.9%.

The beta

Haider considers a range of 0.28 to 0.33 as adequate. There are two other reports which propose a beta between 0.3 and 0.37 and 0.4, respectively (Dockner/Zechner and London Economics) which support the chosen range.

Equity risk premium

The equity risk premium is derived from a comparison of the risk free rate and the returns in equity markets. On the basis of empirical analysis, Haider determines a range of 4.5% and 5.5% and proposes a rate of 5% which is the same value as proposed by Dockner/Zechner. The relevant rate is therefore chosen to be 5%.

The return on equity

Using a risk free rate of 3.9%, an equity risk premium of 5% and a beta of 0.28 to 0.33, the return on equity is ca. 10.1% pre-tax.

How is the cost of debt calculated?

The report by London Economics considers a risk premium of 221 basis points in addition to the risk free rate as adequate whereas Haider suggests 60 basis points which is the value chosen by the ECK. Included in WACC. This results in a rate for debt of 4.54% pre tax.

What gearing level is used?

The proportion of equity is assumed to be 45%, based on a range proposed by Haider of 40% to 50% and a range of 40% to 45% proposed by London Economics. 40% is debt and 15% is capital without any return.

Is the WACC adjusted for tax? If so, how?

Tax shield factor is 34%. This is simply used as an adjustment factor in the CAPM calculation.

Are other industries used as comparators? If so, what industries.

No, expertise from other (international) regulators considered in consultancy reports.

What WACC is currently used by the regulator (i.e. n%)?

Annexe 2: Austria


On the basis of the considerations for the respective building blocks, Haider determines a range of 6.78% to 7.31% pre tax (London Economics: 10.31% to 10.39% pre tax and Dockner/Zechner 8.4% to 8.86% pre tax). The chosen value pre tax is 6,5% (this is the total return on capital, i.e. including the 15% of capital which is non-interest bearing).

It is important to realise that the WACC is only to be applied to interest bearing capital. While it was assessed which proportion, on average (across the gas companies), is interest bearing capital (subtracting for the end of the financial year 2001 shares, bank deposits, etc), it was finally decided to take into consideration the actual interest bearing capital of each company to determine the size of the interest bearing capital (it is not clear whether this was fully taken into account though).

Are there any proposed changes to the methodology used to calculate the WACC?

No.

Table 21: Determination of the WACC – Austria

INFORMATION SOURCES

Company web-sites (no specific documents, online information)

• www.omv.com

• www.evn.at

• www.ooegf.at

• www.aggm.at

Information from regulator

• www.e-control.at (no specific documents, online information)

•

•

•

• • •

•

Bernhard Haider: “Gutachten zur Bestimmung eines angemessenen Kapitalkostensatzes für Gasnetzbetreiber in Österreich”, November 2003 (consultancy report)

Unpublished reports on cost of capital by London Economics and Dockner/Zechner (details provided verbally by contact at e-control – reports not available)

Information provided in conversations with contacts at E-control

Legislation (provides details on institutions and form of control)

GWG II (Gaswirtschaftsgesetz II) - law that provides the legal framework for the economic organisation of the sector

Gassystemnutzungstarifverordnung, (GSNTVO 2004) - the decree that implements the law and includes details of tariffs

Energieregulierungsbehördengesetz - law that stipulates how the regulatory framework is set and the regulatory authority is organised, its competencies and related matters.

FLAVO (decree)

Annexe 2: Austria

http://www.omv.com/

http://www.evn.at/

http://www.ooegf.at/

http://www.aggm.at/

http://www.e-control.at/


Annexe 3: Belgium




Fluxys is the Belgian gas transmission company. Fluxys provides transport services from an entry point on its network to connections with distribution grids and end users (large industrial customers and electricity generators).

Gas transmission was formerly undertaken by a vertically integrated monopoly company, Distrigas. This company was split into two as part of the liberalisation process required by the EU Directive. The two companies created were Distrigas, with responsibility for trading activities ranging from the sale of natural gas in Belgium and Europe to international transport capacity trade; and Fluxys, with responsibility for natural gas transport, storage and terminalling activities together with related services.


Private ownership. Belgian State holds a golden share.

Shareholders are as follows2:

• • • •

Suez Tractebel (57.25%)

Publigas (31.25%)

First market of Euronext Brussels (11.5%)

Belgian government (Single golden share)


The transmission business in Fluxys is part of a wider group that also provides gas storage services and operates LNG terminalling and transport services. The group operates the Zeebrugge Hub, undertakes gas operations services (through is subsidiary GMSL) and ICT, and provides ancillary natural gas transport services (including consultancy in metering and natural gas analysis and cathodic protection). The group also provides transit services for natural gas transmission from entry point at the Belgian border to an exit point at the Belgian border.

The transport services, for which there are regulated tariffs, include capacity services, flexibility services, pressure reducing services, odorisation services and quality conversion services.


None known

Table 22: Basic facts on GTS operator - Belgium

2 www.fluxys.be

Annexe 3: Belgium



Fluxys operates 3,160km of high-pressure pipelines (maximum authorised operating pressure=65 bar) and 540km of medium-pressure pipelines (maximum authorised operating pressure 15 to 65 bar). There are approximately 51,000 km of low pressure distribution pipelines.


There are interconnectors with the UK, Netherlands, Norway, Germany, Luxembourg and France. Private contracts are primarily used to ensure cooperation between these systems.


None known

Table 23: Technical information on gas sector - Belgium

Annexe 3: Belgium




The regulatory regime for gas transmission was introduced through a series of Acts and Royal Decrees in 2002 and 2003, as part of the general industry restructuring to reflect liberalisation of the gas sector.

The Gas Act (August 2003) governs the operations and use of the gas transportation network. This Act is based on the 1965 Gas Act which was subsequently modified in April 1999, July 2001, December 2002, February 2003 and March 2003. The Gas Act specifies a system for regulated access to transportation grids which has since been implemented by royal and ministerial decrees. Negotiated TPA was previously in place.

The Royal Decrees of April 2002 and February 2003 relate to regulation of gas transmission and distribution tariffs respectively. The Royal Decree of May 2002 relates to authorisations for natural gas transmission. Public service obligations are dealt with in the Royal Decree of October 2002 and the Decree of April 2004 relates to the requirement to adopt a Code of Good Conduct for access to the gas transmission grid.


There are four legislators and three regulators in total: one legislator at Federal level and one for each region; and one regulator at federal level and two regional regulators (for the Flemish and Walloon regions).

The federal regulator is the CREG and it is this body which is responsible for regulating gas transmission tariffs. The Flemish regulator is the VREG and the Walloon regulator is the CWaPe.

Only the Flemish and Walloon regions have introduced liberalisation legislation and have their own regulators responsible for gas regulation. There is no competition or a gas regulator in the Brussels-Capital region.


The CREG is an administrative body that is fully independent from elected officials and gas companies.

Review of regulator’s functions with respect to prices and quality

The CREG is responsible for gas matters which require uniform implementation in Belgium, including gas transport and storage tariff regulations. This is therefore the regulator of interest in this study.

The CREG has two roles:

•

•

Advisor to the Minister for Economy and Energy Affairs on the organisation and functioning of the gas market. Role includes drafting of proposals and Royal Decrees and undertaking studies designed to assist the Minister.

Enforces existing laws and decrees relating to the organisation and functioning of the gas market.

In this enforcement role the CREG approves the tariff proposals submitted by Fluxys each year. Approval is given for tariffs which reflect reasonable costs.

The Gas Act requires the transportation companies to ‘operate, maintain and develop

Annexe 3: Belgium


their activities under economic, sustainable and secure conditions with due regard to the environment’3. Companies are also prohibited from ‘discriminating between users or classes of users of their infrastructure, particularly in favour of their affiliates’4. The CREG and regional regulators are responsible for ensuring that Fluxys operates according to these obligations.


Decisions by the CREG are subject to judicial review by the Conseil d’Etat. Grounds and procedures for appeal follow those generally applicable under Belgian Law.

‘In its policy statement of July 2003, the (federal) government indicated that a right to judicial review of the acts of the CREG before the Cour d’Appel de Bruxelles/Brussele Hof von Beroep would be introduced’5.


Court of law – Supreme Administrative Court of Belgium


Public service obligations set by regional regulators.


None known

Table 24: Regulatory institutions - Belgium

3 Global Competition Review (2004), getting the deal through – Gas Regulation 2004.



Annexe 3: Belgium



Fluxys moved from a system of negotiated TPA to regulated TPA for domestic transport charges in November 2002. Transit transport charges are determined through negotiations.

Eligible clients (which vary in definition by region) and gas supply companies can seek access to the transportation network and they pay a fixed tariff which is approved by the CREG.

Tariffs for the use of a transportation grid and tariffs for ancillary services must receive prior approval from the CREG. This is generally done on an annual basis, although derogations are allowed for certain circumstances. Decisions on tariffs are published in the Belgian and EU Official Journals and must be communicated to network users directly. Regulated tariffs for 2002, 2003 and 2004 have been approved by the CREG.

Under the Gas Act and the Royal Decree of 15 April 2002, gas transportation tariffs must:

• •

• •

be non-discriminatory and transparent;

be broken down into sufficient details to reflect the conditions of use of the grid, the type of ancillary services, and any additional burden relating to the financing of public service obligations;

reflect cost and include a fair return on capital; and

if possible, maximise the utilisation of the capacity of the network.

Furthermore, according to the Royal Decree (April 2002), the level of the tariffs ‘must allow for sufficient revenues to enable the transportation company to fulfil its legal duties, as well as for an equitable margin of profit to remunerate its investments in the transportation grid and to ensure the long-term development of the network’6. They should also be designed ‘to maximise the use of the capacity of the grid’7.

The ‘Code of Good Conduct’, adopted in The Royal Decree of 4 April 2003 and published in May 2003, requires non-discriminatory access to and use of the gird. The Code sets ‘minimum technical requirements for connection to the transportation grid, together with operational rules governing the management of energy flows on the network, taking into account exchange with other interconnected systems and balancing requirements. It also allows the gas transportation undertaking to take the necessary steps to maintain or restore balance in the grid’8.


Ex-ante approval of proposed tariffs to ensure reasonableness of the budgeted costs – assessed on the basis of a cost plus approach, taking account of the reasonableness of the costs.

Fluxys submits its budget and tariff proposal each year for the following year to CREG for approval.


Annual




Annexe 3: Belgium



Tariffs for the following gas transmission services are regulated: capacity services, flexibility services, pressure reducing services, odorisation services and quality conversion services. The transmission price control review is separate from that for other gas services, particularly distribution.

Costs are divided into each service on ‘the basis of objective criteria’9.

A separate control exists for Fluxys LNG.

Methodology used to the set the price control (please describe, particularly if non-standard)

The CREG assesses the budget and tariffs of Fluxys each year by comparing the proposal to their assessment of reasonable costs. A similar approach is used to that which had already been developed in the electricity sector.

Required reasonable costs are calculated as required operating expenditure, including depreciation, plus a fair return on capital. The assessment of capital cost is based on the calculation of an allowed WACC times an allowed regulatory asset base plus working capital. CREG has guidelines on what a ‘fair return on capital’ is but this is not embedded in law.

Fluxys’s budget, and hence tariffs, will be adjusted if different to the CREG’s assessment of reasonable costs.

Structure of the control

Similar to a revenue control essentially – revenue earned from proposed tariffs should be sufficient to cover required reasonable costs, on a service-by-service basis.

Does the regulator intervene on the structure of charges?

Under the Gas Act and the Royal Decree of 15 April 2002 the tariff structure must take account of the capacity reserved and necessary to permit the transportation service.

Fluxys previously had a point-to-point capacity reserving system. This was converted into an entry-exit system from April 1st 2004.


Policy statements made on 14th July 2003 by the federal government and on 28th November 2003 by the Minister for Economy and Energy Affairs indicated that reforms would be introduced, as part of the implementation of the Acceleration Directive, that include improving the procedure for the approval of tariffs by the regulator10.

Table 25: Regulatory regime - Belgium

9 Fluxys (2003), Fluxys natural gas transport services in Belgium Conditions & Tariffs as from 1 January 2004.


Annexe 3: Belgium




A RAB is used by The CREG in its assessment of the ‘fair return on capital’.


CREG (2004), Rapport TG2003, indicates that a RAB and WACC are used to determine the required capital cost but no detailed description of the methodology used is provided. The regulator indicates in this document that the approach is consistent with international practice and with the approach used for electricity in Belgium. For example, it is indicated that the RAB is based on a mixture of the ‘market value’, ‘current cost accounting’ and ‘depreciated replacement cost’ and that the WACC used is consistent with that used in the electricity sector.

Although the tariffs are approved annually it seems that the CREG has established a system with an initial RAB (as of 31/12/2002) that is rolled forward over time and reviewed for each set of tariff proposals.


The opening value of the RAB for Fluxys is defined as the MEA value estimated on 31/12/2002, plus investment and less depreciation for the first six months in the following year. This is termed the economic reconstruction value of the tangible assets. The adjustment for six-month investment and depreciation reflects the implicit assumption that investment takes place in the middle of each year.

The depreciation rate for historical assets is based on the rates sets by the Control Committee for Electricity and Gas (the old regulator). This opening value is classed as an economic replacement value.

The valuation is based on a detailed inventory of assets, using the monetary value of the assets at 31/12/2002 and taking account of current technology.


Although not formally stated by The CREG, the methodology appears to have been chosen on the grounds that it reflects the true economic replacement value of the assets. Furthermore, the methodology is consistent with that used in the electricity sector. There are no guidelines or strong statements in place that explain what other options were considered however or why it was important to use an economic replacement value approach.


31st December 2002

What accounting approach is used to value the historic assets?

MEA value for historic assts


Tangible assets only


MEA value based on asset inventory, monetary values as of 31/12/2002 and current technology. The MEA approach incorporates an inflation adjustment by definition (current replacement cost of assets given current technology).

Annexe 3: Belgium



Not stated.


A detailed technical inventory was undertaken by Fluxys. The valuation was then based on the monetary values of the assets at 31/12/2002 (i.e. the cost of replacing the assets at that time) taking account of current available technology.


All assets are depreciated on the basis of the rates outlined in Guidelines from the CREG.

A straight-line rule is used in all cases, with the rate varying according to differences in the asset lives as follows.

Industrial buildings – 3%

Administrative buildings – 2%

Pipelines – 2%

Metering, pressure reduction and compression devices – 3%

Storage installation – 3%

Teletransmission and optical fibres – 10%

Equipment and furniture – 10%

Rolling stock – 20%

Half the annual budgeted depreciation is subtracted when the RAB is rolled forward each year. Overtime the RAB is expected to converge to the acquisition value of the assets.


The MEA value is calculated as a new construction value which subsequently is amortised according to the depreciation rules discussed above. When the amortised value (residual value) drops below 20% of the MEA value, a minimum of 20% is maintained for some assets (pipes; metering, pressure reduction and compression devices; storage installation; and teletransmission and optical fibres).

Assets therefore remain in the RAB until they are put out of service or sold, even if they have exceeded their economic life.


The assumed asset lives for depreciation purposes are:

Industrial buildings – 33 years

Administrative buildings – 50 years

Pipelines – 50 years

Metering, pressure reduction and compression devices – 33 years

Storage installation – 33 years

Teletransmission and optical fibres – 10 years

Equipment and furniture – 10 years

Rolling stock – 5 years


Annexe 3: Belgium


The RAB is rolled forward from the previous year’s value (which was the initial value in 2002 for the 2003 tariff assessment) by adding actual additions and subtracting withdrawals and depreciation. Additions and withdraws are added (subtracted) at half their acquisition value for the next year to reflect the assumption that investment occurs mid-year. These acquisition investment values are not re-valued or indexed when rolled forward in the RAB in future years. Working capital is added to this value and the amounts paid by customers (for example for new connections) are deducted. The initial value of the RAB is not revalued for each annual tariff review.


None known

Table 26: Methodology used to calculate the RAB - Belgium


Annexe 3: Belgium



Only tangible fixed assets are included in the RAB. No intangible assets – such as working capital – are included. These are added to the RAB to determine total required costs.

Only budgeted costs that are deemed reasonable by CREG are included in the RAB


None known


In each year the RAB is rolled forward to include actual reasonable additions minus actual disposals and actual depreciation in the previous year. All additions and disposals are based on acquisition values.


There is no mention of a ‘used and useful test’.


There are no incentives for capital efficiency with this annual cost-plus regime


Not known

Any other information of interest on treatment of capital investment

CREG is responsible for developing a 10-year investment plan to secure investment in gas infrastructure for transport and storage. The plan is indicative of requirements and is provided as advise to the Minister but it is non-binding on Fluxys. However, if CREG observes that Fluxys is not using its initiative to undertake required investment levels CREG can, and must, react under Belgian Gas Law. In this sense investment remains a private decision for the firm but it is monitored by the regulator and the regulator has a framework for security of supply in mind when undertaking this monitoring. As discussed above the cost of investment is guaranteed in tariffs but capped according to the CREG’s assessment of what costs are reasonable11.

Table 27: Treatment of capital expenditure in the RAB - Belgium

11 Chris Cuijpers, Principal Advisor at the CREG, ‘Securing investments in Gas Infrastructure: Role of

Ten-year plans in Belgium’, IEA Workshop with gas regulators on security of supply in liberalised markets, IEA Headquarters, Paris 27 June 2003

Annexe 3: Belgium




CAPM – return on equity equal to the risk free rate plus beta times equity risk premium.


The risk free rate

The rate used was the average (arithmetic) rate of return of 10 years government bonds issued the year before. The value in 2003 was 5.112%.

The beta

A equity beta of 1 was used for Fluxys in 2003.

Equity risk premium

The market premium was calculated as the difference between the return earned by a basket of shares on the Belgium market and the risk free rate. The value in 2003 was 3.5%.


The cost of debt is based on the actual interest on debt paid by Fluxys. That is, an embedded cost approach is used. A debt premium of 0.7% (70 basis points) was used in 2003.


The ratio of equity fund to borrowed fund used by CREG was 33:67


Cost of equity adjusted to pre-tax basis using actual tax rate paid by Fluxys.


None specified

What WACC is currently used by the regulator (i.e. x%)?

The pre-tax WACC used in 2003 was approximately 7%, but varies by company according to company-specific cost of debt (Frontier calculation based on above parameter values).

Table 28: Determination of the WACC – Belgium

INFORMATION SOURCES


• www.fluxys.be

• Fluxys (2003), Fluxys natural gas transport services in Belgium Conditions & Tariffs as from 1 January 2004.

Annexe 3: Belgium

http://www.fluxys.be/



• www.creg.be

•

• •

CREG (2004), Rapport TG2003 – relatif ‘aux tariffs de raccordement et d’utilisation du reseau de transport de gaz naturel ainsi qu’aux tarifs des services auxiliaires appliques au cours de l’annee 2003, 24 Mars 2004

CREG (2004), Annual Report 2003

CREG (2003) Lignes directrices (R)030618-CDC-219: Lignes directrices concernant la marge bénéficiaire équitable applicable aux entreprises de transport du gaz naturel et aux gestionnaires des réseaux de distribution du gaz actifs sur le territoire belge

• CREG (2002) Décision (B)020926-CDC-95: Décision relative à la demande d'approbation relative aux tarifs de raccordement et d'utilisation du réseau de transport ainsi que des services auxiliaires de la SA FLUXYS pour l'année 2002


• • • • • • •

• • •

The Gas Act (August 2003)

Royal Decree (April 2002)

Royal Decree (May 2002)

Royal Decree (October 2002)

Royal Decree (February 2003)



Other

ARGB, Development in the Natural Gas Sector in Belgium, August 2003

Global Competition Review (2004), getting the deal through – Gas Regulation 2004.

Chris Cuijpers, Principal Advisor at the CREG, ‘Securing investments in Gas Infrastructure: Role of Ten-year plans in Belgium’, IEA Workshop with gas regulators on security of supply in liberalised markets, IEA Headquarters, Paris 27 June 2003.

Annexe 3: Belgium

http://www.creg.be/

http://www.creg.be/pdf/Lignes_Directrices/Div-R219FR.pdf

http://www.creg.be/pdf/Decisions/Div-B95FR.pdf


Annexe 4: France




There are three transmission operators:

Gaz de France

Compagnie Française de Méthane

Gaz de Sud-Ouest


Gaz de France: state owned

Compagnie Française de Méthane: joint owned by Gaz de France (55%) and Total (45%), but as a result of CRE pressure, to be transferred solely to Gaz de France

Gaz du Sud-Ouest: joint owned by Gaz de France (30%) and Total (70%), but as a result of CRE pressure, to be transferred solely to Total.


See above


It is intended that the number of transporters is reduced from three to two (see above). Equally, the French government is in the process of opening up Gaz de France to private capital. The implementation of the second Gas Directive will require the legal separation of the transportation arms of the current vertically integrated companies.

Table 29: Basic facts on GTS operator - France

Annexe 4: France



The respective length of the companies’ networks are as follows:

• • •

Gaz de France: 24,000 km

CFM: 7,000 km

GSO: 4,500 km


There are five international interconnectors:

• • • • •

Dunkerque, Norway

Fluxys-GDF, Belgium

Obergailbach, Germany

Oltingue, Switzerland

Col de Larrau, Spain

Gas is imported from four main countries: Norway, Algeria, Russia and Netherlands.


None known

Table 30: Technical information on gas sector - France

Annexe 4: France




The Gas Law of 3 January 2003 provided for certain elements of the gas market regulatory framework. In particular, it placed obligations on the regulator to make proposals to government who then formally set tariffs via a decree.


Commission de Régulation de l’Energie (CRE)


Independent administrative authority composed of seven members appointed for a term of six years.


Under the law of 3 January 2003, the CRE proposes tariffs to government, who then consult on the proposals, and taking into account the view of the Conseil de la Concurrence, issues a decree in the Conseil d’Etat to set tariffs.

The government is the sole entity with the power to adopt regulations in the gas sector. The CRE has a supervisory activity. Its main task consists in ensuring non-discriminatory access to the networks or to LNG facilities.

According to Article 7 of the Gas Law, tariffs for the use of the public transmission and distribution systems are adopted jointly by the ministers for economy and for energy, upon a proposal made by the CRE.

The CRE also elaborates the accounting principles relating to the unbundling of generation, transmission and distribution activities and monitors their implementation to avoid any discrimination, cross-subsidization or any other restriction of competition.


Cour d’appel of Paris

Conseil d’Etat


Any decision taken by the CRE may be subject to an appeal before the Cour d’appel of Paris. The appeal does not have a suspensive effect. However, a request for a stay of proceedings may be made to the president of the Cour d’appel of Paris.

Regarding the penalty decisions imposed by the CRE, any request for a stay of execution or appeal should be introduced before the Conseil d’Etat. When they relate to financial penalties, requests for stay of execution have a suspensive effect.


None known


None known

Table 31: Regulatory institutions – France

Annexe 4: France



Regulated TPA exists in France, with the CRE proposing tariffs to the government who then take the final decision, following consultation, on what the tariff level should be.

The three transporters all have different tariffs, and while they are all based broadly around entry/exit within defined “balancing zones”, they also have slight differences in their structures.

There are 8 “balancing zones” on the network:

• • • •

• • •

One for GDF’s low calorie network

Four for GDF’s high calorie network;

Two for CFM’s high calorie network; and

One for GSO’s high calorie network.

There are tariffs for entry, exit, regional transport and delivery for each zone. There is then also a tariff for transport between zones.

Article 2 of the Gas Law provides that “eligible customers” and suppliers or their agents have a right to access natural gas transmission and distribution networks and LNG facilities under conditions provided for in agreements with the operator concerned.

According to the Law, eligible consumers may purchase their gas from the producers of their choice (there is detailed definition of eligible consumers – basically, large final consumers and gas suppliers).

Once concluded, the contract for access should be transmitted to the CRE. Any refusal to conclude such a contract by a network or infrastructure operator has to be substantiated and notified to the applicant and to the CRE. The criteria for refusal may only be based on considerations relating to:

lack of capacity or other technical/network security issues;

privileged access decided by the minister for energy in order to ensure compliance with public service obligations; or

the fact that the system operator faces financial and economic difficulties owing to ongoing long-term “take-or-pay” supply agreements.


The CRE propose a set of tariffs (structure and level) to government, and they are formally required to be approved by government prior to their entry into force.


The CRE’s first proposal to government on gas transportation tariffs was made on 25 July 2003, for tariffs intended to enter into force from 1 July 2004. These tariffs were intended to last for 12 to 18 months.

As a result of changes to the market since July 2003, the CRE has recently (6 September 2004) completed a consultation on a new tariff proposal. The CRE’s proposal will be presented to government in due course.


The tariffs are intended to remunerate transportation services only. There are separate tariffs for distribution, storage and LNG terminals.


The CRE base the tariffs on a “cost plus” methodology. They are set to cover the costs

Annexe 4: France


of operating and capital expenditure, and a return on assets.

Operating costs are determined with reference to the level of costs determined in 2002 (which were considered by a special government commission established in December 2001) but taking into account expected efficiency improvements in 2003-4. The operating costs are subject to an audit arranged by the CRE.

Capital costs, comprising depreciation and return on capital were calculated according to the following methodology:

•

•

•

The value of assets in the asset base was calculated according to the initial value of the assets, adjusted by inflation from the date of commissioning and depreciated according to time in use. This asset base then evolves as a result of an annual revaluation, the commissioning of new assets, and the retirement of old assets;

An allowance for depreciation is then made based on linear depreciation over the economic life of the assets (50 years for pipes, 30 years for compressor installations, and 10 years for other technical installations).

The allowed rate of return is based on the weighted average cost of capital. For assets in operation on 1 January 2004, the allowed pre tax rate of return was 7.75% (real). For new investments after this date, a higher rate of return of 9% (real, pre-tax) is allowed. For new investments which can be demonstrated to reduce congestion and increase competition, the rate of return can be increased to 12% (again, real pre-tax) for a limited period (5 to 10 years).


There is no formal revenue control. Tariffs are reset periodically on a cost-plus basis.


The regulator does have a say on charges / tariff structure. The regulator’s proposal to government includes full details of the charging structure as well as level of the tariffs.

If yes, what type of charging structure is used?

The tariff structure is, as noted above, broadly entry / exit within each of 8 balancing zones, with separate charges for transportation between zones. There are a mixture of capacity and commodity based charges. While it appears that the majority of the charges are capacity based, there does not appear to be an explicit predetermined capacity / commodity split.


As a result of changes to the market since July 2003, the CRE has recently (6 September 2004) completed a consultation on a new tariff proposal. The CRE’s proposal will be presented to government in due course.

The new proposal is aimed at reducing the number of balancing zones. The intention is that, in the longer term, there should only be three zones for the whole of France – two for Gaz de France and one for GSO. Gaz de France estimate that the physical investment required to facilitate the reduction in the number of zones is of the order of €330M (they argue that the investment is required to remove the potential for congestion within zones).

Table 32: Regulatory regime – France

Annexe 4: France




The RAB is used in the determination of cost-based tariffs. There is no formal longer term price restraint.


The value of assets in the asset base was calculated according to the initial value of the assets, adjusted by inflation from the date of commissioning and depreciated according to time in use. This asset base then evolves as a result of an annual revaluation, the commissioning of new assets, and the retirement of old assets


The initial asset value was set by a specific commission – la Commission Houri – which was set up in 2001 to make an evaluation of the assets when Gaz de France had to buy them from the state. The details of the report are not public. The CRE simply took the calculation as given to assess tariffs.


The initial value of the assets was set by la Commission Houri and the details of the methodology used is not public.


Not public.


Appears to be asset value in 2001, when Gas de France hah to buy assets from the State.


Not public


Not public


Not public


Not public


Not public


Not public – undertaking by a specific commission for a specific purpose (transfer of assets from State to Gaz de France)


Straight line depreciation for rolling forward to initial value to determine annual value of RAB.

Depreciation used for historic assets to assess initial value is not publicly available, but

Annexe 4: France


indication is that it reflected time in use of assets.


CRE makes the following assumptions on asset lives:

Pipes – 50 years;

Compression stations – 30 years

Other technical installations – 10 years


The RAB is rolled forward for the length that the tariffs are expected to remain in place (12-18 mths).

At each tariff review (annual) the RAB is equal to the value of the RAB in the previous period revalued by inflation of assets from their entry into service, depreciation, the commissioning of new assets and the retirement of old assets. The documents indicate that book values of additions and withdrawals are updated by inflation.


None known

Table 33: Methodology used to calculate the RAB - France


Annexe 4: France



There is no detailed definition given in the documentation.


No – however, see above on differential returns.


There is no history of investment review.


There is no history of investment review


There is no history of investment review.


There is no statement of the way the approach deals with work in progress.


None are indicated by the documentation

Table 34: Treatment of capital expenditure in the RAB - France

Annexe 4: France




The approach used to derive the (three) weighted average costs of capital is not made public by CRE.


The approach used to derive the (three) weighted average costs of capital is not provided.


The documents indicate that the gearing level used for the WACC calculation is based on the CRE’s judgement.


Not specified in the documents – just says “real pre-tax”


No.


For assets in operation on 1 January 2004, the allowed pre tax rate of return was 7.75% (real). For new investments after this date, a higher rate of return of 9% (real, pre-tax) is allowed. For new investments which can be demonstrated to reduce congestion and increase competition, the rate of return can be increased to 12% (again, real pre-tax) for a limited period (5 to 10 years).


None are indicated by the documents.

Table 35: Determination of the WACC – France

INFORMATION SOURCES


• www.gso-transport.com

• www.cfm-gaz.fr

• www.gazdefrance.com


• www.cre.fr

• CRE(2004), Rapport d'activite 2004, September 2004

Annexe 4: France

http://www.gso-transport.com/

http://www.cfm-gaz.fr/

http://www.gazdefrance.com/

http://www.creg.be/


• Information provided in conversations with contacts at CRE

Legislation

•

•

Gas Law of 3 January 2003

Other


Annexe 4: France


Annexe 5: Germany




Several operators:

… • • • •

…

Operators with operating area broadly ring-fenced among them are

E.ON-Ruhrgas

RWE Energy (formerly Thyssengas, RWE Gas)

VNG

BEB

Wingas (overlaps with other operators)

Some further 20 regional distribution operators


• • • • •

E.ON-Ruhrgas (private)

RWE Energy (part private, part joint municipal ownership)

VNG (part private, part joint municipal ownership)

BEB (private)

Wingas (private)


• • •

• •

E.ON-Ruhrgas – 100% subsidiary of E.ON

RWE Energy - 100% subsidiary of RWE AG

VNG – owned by EWE (47.9%), East German municipalities (25.79%), BASF (via Wintershall, Kassel) (15.79%), Gaz de France via EEG Berlin (5.26%), ZGG-Zarubezhgaz-Erdgashandel-Gesellschaft mbH, Berlin (5.26%).

BEB (private) –Shell (50%), Exxon Mobil (50%).

Wingas (private) – BASF (via Wintershall) (65%), Gazprom (35%)


Changes in ownership structure of VNG and Wingas possible. These would be driven by private investment decisions

Table 36: Basic facts on GTS operator - Germany

Annexe 5: Germany


20%

50%

16,9%

98.87%

6,4% 56,4%

25.9%

10,02% 86,58%

24,44%

37,7%

53.1%

50%

35%

65%

50%

50%

100%

RWE GroupWintershall Group

E.ON-Ruhrgas Group

15,79%

Ferngas NordbayernFerngas Nordbayern

20%

Former subsidiaries, integrated into RWE Energy since Feb 04

100%

27.66%

11%

27.66%

47,9%

50%

5,26%

Thüringen.Thüringen.Thüringen.

EWE Group

4,9%

50%

28,76%

BEB Group

Figure 2: The German gas wholesale market – shareholders and shareholdings of GTS

Annexe 5: Germany



The total length of gas pipelines in Germany is around 351.000km.12 Three types of gas pipelines are distinguished with regard to their pressure:

• • •

low pressure pipes operate with up to 0.1 bar;

medium pressure pipes operate with between 0.1 and 1 bar (total length of low-and medium pressure pipelines: 302.164)13;

high pressure pipes with a pressure of 1 bar and above14 (total length of high pressure pipelines in Germany 49.466 km)15.

Degree of interconnection with other gas systems (state countries)16

•

• • • •

E.ON Ruhrgas – with BEB, RWE Energy, VNG (D), GTS, Gasco (NL), Distrigaz, Fluxys (B), Gastra (DK), Transgas (CZ), OMV (A), Gaz de France (F), Transitgas (CH), Soteg (Lux),

RWE Energy - with E.ON Ruhrgas, BEB, VNG (D), GTS, Gasco (NL),

VNG – with RWE Energy, E.ON Ruhrgas (D), PGNIG (PL), Transgas (CZ)

BEB (private) – with E.ON Ruhrgas, RWE Energy (D), GTS, Gasco (NL), Gastra (DK),

Wingas (private) – with GTS (NL), Distrigaz, Fluxys (B), PGNIG (PL), Transgas (CZ), OMV (A)


New pipeline through Baltic sea to directly connect Russia and Germany (official name: “North European Pipeline”). The deal with estimated construction cost of 2.5 bn Euros was signed between Gazprom and E.ON in July 2004 on a state visit of Chancellor Schröder to President Putin. According to the press, Wingas is considering to join the Joint Venture as well. The Pipeline will have a length of 1,189 km, ranging from Vyborg (north-west of Petersburg) to Greifswald in Mecklenburg-Western Pomerania.

Table 37: Technical information on gas sector - Germany

12 EWI Cologne (2003) “Integrierte Mikrosysteme der Versorgung: Sektorreport Gas”, Report for the

German Federal Ministry of Education, Download: http://www.uni-koeln.de/wiso-fak/energie/Aktuell/Sektorreport.pdf .

13 EWI Cologne (2003).

14 Source: http://www.ampere.de/gasmarkt/inhaltsseite_glossar.html.

15 This number can be broken down into long-distance transmission pipelines of 44,175km and transmission pipelines from exploration companies (EWI Cologne 2003).

16 Source: http://www.gte2.be/download/gridmap/GRIDMAP_8july2004.pdf.

Annexe 5: Germany




Currently self-regulation through Association agreement II (Verbändevereinbarung). Proposals to introduce a regulatory regime are under consideration.


Bundeskartellamt (Competition Authority) Sector specific regulation under discussion; would be managed by RegTP (the telco regulator)


Bundeskartellamt – independent body, president effectively appointed politically RegTP (designated future regulator) – independent body, president and 2 vice presidents effectively appointed politically; post for one additional vice president may be created to focus on energy.


Economic aspects of regulation are currently governed by Association agreement between representatives of network operators – BGW and VKU – and network users VIK and BDI. Technical standards are set by the DVGW Association which is governed by the industry itself. Bundeskartellamt only gets involved with pricing decisions ex-post; only precedence is the case Enron vs. MVV and GVS in 2001 which was dropped because the network operators refused to provide information (e.g. on cost; the BkartA was looking to verify whether the actual tariffs had been based on historical cost, but it was denied access to the relevant cost information. The BkartA would have legally had the authority to require the information. It is not clear why the office did not make use of that authority).


Oberverwaltungsgericht Düsseldorf (Higher Adminsitrative Court)


Court of law


Not relevant


New regulatory framework under discussion. Draft law passed in the lower chamber (Bundestag) but halted in the Upper House (Bundesrat). Law is likely to go into the arbitration committee between Bundestag and Bundesrat. Contentious issues (of the current draft) include:

• • • •

whether to decree the accounting approach (proposal: Nettosubstanzerhaltung, net working capital maintenance model) by law; whether to include principles of incentive regulation in the law (the draft is very vague); whether to concentrate on ex post regulation (current draft) whether to concentrate all regulatory authority with a federal regulator (current draft; alternatively some authority could rest with the Länder)

Draft connection and tariff decrees in preparation assuming that original draft law will be passed.

Table 38: Regulatory institutions – Germany

Annexe 5: Germany



Given the lack of clarity about future arrangements we focus on the existing regime, i.e. based on the Verbändevereinbarung which exists with relevant competition law.

Tariff levels are set independently by the operators based on principles outlined in the Association agreement II. This is therefore a self-regulated negotiated TPA regime.

Effectively point-to-point tariffs, BEB has introduced entry exit tariffs in July 2004.


Tariffs expected to meet principles laid out in the Association agreement II. Ex-post assessment of tariffs by competition authority in case of dispute (comparison for long-distance tariffs; cost based for regional transmission tariffs).


No review of tariffs by a regulator or the competition authority - only case of challenge was dropped(see above). Tariffs are reset periodically by companies themselves according to the Associated Agreement II.


Separate tariffs set for gas transmission. Storage, ancillary services, etc not covered


Under the Association agreement II , “comparative prices” are to be applied for long-distance transmission (based on claim of effective pipe-to-pipe competition at the long distance level) and cost-reflective prices are required for regional transmission. The comparative approach for long-distance transmission has not been tested.

It is understood that a cost-reflective approach is preferred by the Ministry for all levels and this may be considered as part of current reform discussions.


For regional gas transmission: revenue control (Revenues should be sufficient to achieve allowable return while companies can decide on tariff structure).


Not so far (see also above).


Notional path with option for traders to net out entry exit differences within their portfolio to pay only for notional net flows (entry-exit by BEB)


Strengthening of entry-exit aspects in the forthcoming connection decree. Various proposals exist:

BEB model – this model implemented in July 2004 provides more flexibility than the model described below

BGW/VKU proposal - a proposal was submitted in October 2003 to the ministry from the

Annexe 5: Germany


association of gas companies (BGW/VKU proposal), which is more restrictive than the more competitive friendly approach implemented by BEB for their network. Although details are not clear yet, a draft access decree has leaked from the ministry that appears to be very close to the BGW/VKU approach. The decree is discussed in the September issue of Energiewirtschaftliche Tagesfragen, a monthly expert publication. Based on the information given in that press article, an entry exit model will be implemented with the following features:

…

… …

…

…

Multi entry-exit model: Separate entry-exit model for each of the two transmission levels (regional and supra-regional) for each network owner, with the possibility to divide networks into further zones.

Booked capacity must be nominated 7 workdays ahead to certain entry-and exit points (in essence still point-to-point regime).

Congestion management: First-committed-first served booking regime (no auction), with operators free to apply use-it-or-lose-it regimes. Secondary market is explicitly envisaged, with operators to establish a bulletin board.

Co-ordination between different networks/Zones: Self-commitment of operators to establish grid-coupling agreements - transport management via “agent model” (in essence a separate network service to be paid for).

Network tariffs: Calculated by each network operator separately. The draft decree so far contains no suggestion on how tariffs are set for flows between networks. Long distance transmission tariffs to be set through benchmarking of tariffs in other EU markets (not cost based); distribution network tariffs to be cost based.

We emphasize, that these features of the proposed access agreement are based on a first draft version of the decree, which may be subject to change during parliamentary discussion. Nonetheless, the draft decree indicates roughly the direction of the new network access agreements.

Any other information of interest on access arrangement and/or price restraints

Discussion on the treatment of different gas qualities; balancing intervals and balancing tolerances.

Table 39: Regulatory regime - Germany

Annexe 5: Germany



The following considerations currently only apply to regional and local gas transmission, while a “comparative approach” is used for long-distance transportation tariffs. The described approach is that of the Verbändevereinbarung (Association Agreement II) and hence does not reflect a decision made by a regulator (in contrast to all other countries).


Yes – for assessment of cost-reflective prices of regional gas transmission under self-regulation system.


Book value of assets at each “review”


Historical practice developed in the electricity industry. Dates back to Public procurement rules of the 1950ies, Bundestarifordnung Elektrizität 1990 (has replaced old BtoElt from 1980) and Arbeitsanleitung (1997)17 (and earlier regulation practice in other sectors, e.g. Preisstoppverordnung of 1936).


Not relevant – current book value used at each review. Not a roll-forward methodology


See above – historical practice


Not relevant


Combination of CCA/HCA: “Nettosubstanzerhaltung” (net working capital maintenance). Equity-financed share of assets is valued at CCA (with asset specific price indices), debt-financed part is valued at HCA.


Not specified but expected to be all


Not relevant – no role for a regulator





17 Full title: „Arbeitsanleitung zur Darstellung der Kosten- und Erlösentwicklung in der

Stromversorgung“.

Annexe 5: Germany



Book value of assets taken from accounts


Linear/straight line with period differing by asset class (details in Annex 9 to Verbändevereinbarung II).


For example, depreciation period for gas tanks and most pipelines is 45-55 years, for measurement and control devices 20-30 years, for gas meters 8-16 years.


Not relevant – book value of assets taken from annual accounts. Assumed to reflect standard accounting approach which will be based on book value in previous year plus additions and minus withdrawals and depreciation, with an adjustment for inflation. The inflation adjustment is based on official asset price indices (from the Federal statistical office).

A new value is used each time the transmission operator decides to change his prices. There are no fixed review periods.

Any other information of interest on calculations of the RAB

Ongoing discussion on the reflection of “Scheingewinnbesteuerung” (shadow taxation), i.e. corporate taxes paid on hca accounting profits that are not economic profits (under cca of Nettosubstanzerhalktungs-accounting rules).

Ongoing discussion on treatment of customer contributions (on or off RAB).

Ongoing discussion about the starting book value of assets for the first calculations of tariffs if regulatory regime introduced. Not publicly available.

Table 40: Methodology used to calculate the RAB – Germany


Annexe 5: Germany



The capital expenditures are calculated at the discretion of the companies. The VV Gas does not explicitly define the term capital expenditure, but contains only broad algorithms for the calculation of depreciation and necessary equity (on which the 7.8% return on equity is applied).


No


None


Formally, there is an efficiency requirement in the VV Gas, but this has not yet been applied in practice. The efficiency requirement is very broadly defined as: “The network tariffs have to be based on costs that are necessary for efficient operations of gas company”.


Effectively incentives to show high RAB as efficiency requirement is not effective


Capital assets under construction can be added with their book value to the necessary equity.


Not to our knowledge

Table 41: Treatment of capital expenditure in the RAB – Germany

Annexe 5: Germany




In the VV Gas, the return on equity is set to be 7.8%, including the risk premium. No reference is given how (and based on which model) this cost of capital is calculated. We understand that the industry had commissioned a study with PwC that came up with the figure. PWC used the CAPM.


The risk free rate

No detailed information in the VV Gas.

The beta


Equity risk premium



VV Gas: actual company debt

BMWA proposal for future: benchmark expenditure (e.g. expenditure that would be required at a benchmark interest rate).


Actual levels, but max 40% of equity.


Electricity indirectly


• •

Cost of debt is considered with its actual amount;

Cost of equity is calculated with 7.8% (pre-tax).


An amendment to the German energy law (ENWG), which will govern the regulatory framework for gas transmission and distribution companies, is currently in the process of legislative discussion. No decision has been taken yet, and the new EnWG is not expected to take effect prior to mid 2005. The following statements are based on public debate and may be subject to change during legislative debate.

Overall, except to have a more market based derivation of the return-on-equity, not much is likely to change in the calculation of WACC.

The method for the calculation of the WACC with regard to cost of equity may be based on

• • •

actual capital structure of the companies,

situation on national and international capital markets,

average equity returns granted to comparable companies in other EU countries Cost of debt will probably be considered with is actual amount, as long as the conditions are consistent with market expectations.

RegTP will calculate the allowed equity rate-of-return every two years, beginning with 01st of January 2007. Until that date, the current rate of 7.8% is expected to apply.

Table 42: Determination of the WACC - Germany

Annexe 5: Germany


INFORMATION SOURCES


• •

www.eon-ruhrgas.com

www.rwe.com

• www.vng.de

• www.wingas.de

Legislation

• Association Agreement II (Verbändevereinbarung) - download: http://www.vik-online.de in Infocenter

Other

• • • •

•


Schiffer – „Energiemarkt Deutschland“, Colonge: TÜV-Verlag, 8th edition 2002

Energiewirtschaftliche Tagesfragen (http://www.et-energie-online.de/)

EWI Cologne (2003) “Integrierte Mikrosysteme der Versorgung: Sektorreport Gas”, Report for the German Federal Ministry of Education, Download: http://www.uni-koeln.de/wiso-fak/energie/Aktuell/Sektorreport.pdf .

BMWA (www.bmwi.de)

• Information from conversations with contacts in German Ministry

Annexe 5: Germany

http://www.rwe.com/

http://www.vng.de/

http://www.wingas.de/

http://www.vik-online.de/

http://www.bmwi.de/


Annexe 6: Ireland




Bord Gais Eireann (BGE) – transmission business unit


The company is wholly owned by the Government. It was established as the Gas Development Agency under the 1976 Gas Act, with responsibility for developing and maintaining a system for the supply of natural gas.


BGE is a single vertically-integrated corporate structure made up of a number of business units and subsidiaries. BGE is responsible for the transmission and distribution of natural gas in Ireland. It retains a franchise over supply of gas to domestic customers, and its supply activities to smaller industrial and commercial customers remain regulated. Furthermore, it has interests in combined heat and power and telecommunications infrastructure. The company is also a wholesale supplier of electricity. A Code of Conduct was introduced in 2002 to ‘govern the interaction and relationships between BGE’s business units’(See CER/02/83).

A single licence is granted for the operation of transmission pipelines, governing gas transportation, infrastructure development and maintenance of the network. A separate Distribution Licence covers the low pressure networks for supply to industrial, commercial, residential and new housing sectors. The transmission and distribution activities are currently part of the same business unit.

Bord Gais Energy Supply, a separate business unit, is responsible for buying and selling energy products, the development of new products & services, and customer service support. There is no separation of the franchise and competitive markets within the supply business (although they are regulated differently). All non-domestic customers are eligible for competition, and the domestic market is scheduled to be opened in 2005.

BGE (Northern Ireland) has a licence – since 2002 – to own and operate two transmission pipelines in Northern Ireland. The first of these will link Belfast to Derry and the second links the Republic of Ireland to Northern Ireland (see planned interconnectors below). These pipelines will be regulated by OFREG. BGE is also developing distribution interests in Northern Ireland.


Legal separation of distribution and transmission which will create separate transportation and supply companies (albeit within the same corporate group).

There are plans to complete a €1.4bn infrastructure programme to ensure security of supply for Ireland for 25 years.

Table 43: Basic facts on GTS operator - Ireland

Annexe 6: Ireland



There are approximately 1,850km of high-pressure transmission pipelines and over 8,400km of distribution pipelines. Transmission pipelines operate at a pressure of up to 70 bar (See CER/02/83). Distribution pipelines operates at a pressure of about 4 bar, although a small number operate at 7 bar (See CER/02/83).


There is a sub-sea interconnector pipeline linking Ireland with the UK national transmission system on the Scottish mainland. A second interconnector on the same route is under construction.

An additional spur pipeline – off the second Scottish interconnector – links Ireland with the Isle of Man. This pipeline is owned and operated by BGE and is used to provide gas to the Isle of Man.

Interconnection arrangements (The Connected Systems Agreement) between BGE and Transco are agreed by private contract.


BGE is constructing a pipeline to Northern Ireland which will be used to supply gas to Northern Ireland. This pipe will link up to the second Scottish Interconnector and construction is due to start in 2006.

Table 44: Technical information on gas sector - Ireland

Annexe 6: Ireland




The regulatory regime was established under the Gas (Interim) (Regulation) Act 2002 and has evolved through various consultations and decisions by the regulator. The regulatory regime is closely modelled on that used in the UK, although there are arguably fewer checks and balances (for example, there is no route of appeal to competition authorities in relation to price control determinations).

The regime is reasonably new and hence regulatory precedence has not been firmly established.

The first regulatory review of revenues for gas transmission was undertaken in 2003 for the period 1st October 2003 to 30th September 2007 (previous reviews had been undertaken by Ministers and a single annual review was undertaken by CER when it came into being).


Commission for Energy Regulation (CER)


Independent regulatory agency – established in The Gas (Interim) (Regulation) Act 2002.

The CER is responsible for the granting of consents to lay on-shore transmission or distribution pipelines; the making of regulations relating to agreements (charges and terms) between a pipeline operators and those eligible for TPA to the system; and the licensing of gas undertakings for supply, distribution and transmission and storage.


CER is responsible for the economic regulation of gas supply tariffs for non-eligible (franchise) customers and the regulation or gas transportation charges (distribution and transmission). We consider the transmission charges only here.

Furthermore, the CER has ‘the power to resolve disputes between pipeline operators and any person who is, or claims to be, an eligible supplier or customer’. (See CER/02/83). The Commission can also introduce regulations relating to the method of charging, the form of charging and the nature of information provided to those seeking access. An operator is required to comply with any such regulations. The legislation therefore provides the regulator with the power to intervene if negotiated TPA is in place or to operate a regulated TPA regime, thereby providing discretion and flexibility to the independent agency rather than prescribing formally the type of access arrangements that should be in place. In practice, an ex-ante price cap regime for charges has developed.

When carrying out its functions the CER must ensure it does not discriminate unfairly between Bord Gais and other licence holders or licence applicants. It must also ensure that they protect the interests of final customers when carrying out their functions. In doing this the CER has regard to the need to18:

• promote competition in the supply of natural gas;

18 www.cer.ie

Annexe 6: Ireland


• promote safety and efficiency on the part of natural gas undertakings;

•

•

• • •

•

•

•

secure that there is sufficient capacity in the natural gas system to enable reasonable expectations of demand to be met; and

secure the continuity, security and quality of supplies of natural gas.

The general regulatory principles that CER considers when making its decisions are as follows (see CER/02/83):

enable businesses to attract capital from investors;

encourage efficiency in operations and in investment; and

minimise the extent of regulatory intervention in the day-to-day decision making of the businesses.

The objectives are that any system of regulation must:

be cost reflective, to provide a reasonable assurance that the capital invested in the business will earn the necessary rate of return and that the principal will, in due course, be recovered along with any operating costs;

provide management with a relatively stable and predictable set of incentives for efficiency management decisions; and

specify regulatory constraints in terms of medium to long-term rules for setting cost reflective prices, and requirements to offer services.

The CER approves Codes of Operations, Connection policy and tariffs for equitable Third Party Access to the gas transmission and distribution systems. The CER regulates prices charged to gas customers by certain Shippers/Suppliers. The pipeline operator is required to offer ‘fair, reasonable and non-discriminatory terms for access’. The company must also provide the Commission with a statement of charges for approval and must draw up a schedule of information about the system. CER can give directions for these charges to be amended and the operator is required to comply with the direction.

The CER has an objective to ‘promote competition in gas supply by facilitating the entry of players into the gas market, ensuring access to the gas network on a transparent and non-discriminatory basis, to encourage the efficient operation of the gas industry’ and to ‘ensure the development and maintenance of a safe, secure, and reliable system for the supply of gas, which meetings appropriate performance standards and where investment is based on appropriate commercial criteria’19. The duty to promote competition appears to be interpreted as the need to allow shippers and consumers access to the gas network on the basis of terms that are ‘fair, reasonable and non-discriminatory’. CER has indicated in a number of documents that regulatory decisions may be made which actively facilitate entry.

Under the 2002 Act, the companies are required to send accounting and fiscal data to the CER periodically. According to the CER, ‘Integrated natural gas undertaking are required to keep separate accounts for their gas activities and, where appropriate, consolidated accounts for other non-gas activities, in order to avoid discrimination, cross-subsidisation and distortion of competition’. (See CER/02/83). This is now a licence requirement.

19 CER (2002), Natural Gas Policy Framework, CER/02/83, 19 July 2002.

Annexe 6: Ireland



A decision by CER relating to the granting of a licence or the modification of a licence can be appealed to the Minister within 28 days. The Minister will then set up a case-specific Appeal Panel to review the decision and this panel has all the powers and duties of the CER that are required to undertake the review.

There is also provision for judicial review to the High Court.

The Irish Competition Authority does not operate as an appeal tribunal for CER decisions relating to licence modifications.


Ad-hoc Ministerial Appeal Panel which is set up for individual appeal case.

Court of law for judicial review


The Minister for Communications, Marine and Natural Resources, after consultation with CER and other interested parties, may direct the CER to impose undertakings on licence holders which may be in the general economic interest. Public service obligations relating to security of supply and technical or public safety, regularity, quality and price of supplies and to environmental protection can also be imposed on a natural gas undertaking. In this regard the Minister also has the power to impose a levy on customers to over the additional costs arising from such public service obligations.

The Gas Policy Division of the Department of Communications, Marine and Natural Resources is responsible for policy on security of gas supply, for ensuring that infrastructure development is consistent with the government’s objectives of promoting economic and regional development and enhancing social inclusion, and for North/South gas market developments.

The Minister has the power to issue directives to BGE concerning its financial objectives and how its profits should be used. The Minister also has control over BGE’s Board’s decision on pricing policy for the franchise market. These powers reflect the fact that the company is fully state owned.


None known

Table 45: Regulatory institutions - Ireland

Annexe 6: Ireland



Conditions for Third Party Access (TPA) were included in the Gas Act 1976 and amended in the Gas (Interim) (Regulation) Act 2002. Regulation of access arrangements was introduced after 2002 when the CER was set up.

TPA is available to all Bord Gais customers who consume an annual volume of greater than 0.5 million standard cubic meters (mscm) (181,000 therms or 5.25 GWh) at a single site. Third-party access can also be requested by holders of Petroleum Leases, local gas suppliers and operators of gas-fired generating stations. This corresponds to 75% of the industrial and commercial sector and 85% of the total gas sector. The aim is for full liberalisation by 2005.

Regulated TPA is in place for the transportation system with published tariffs which are approved by the CER. Gas transmission tariffs were reviewed by the Department of Public Enterprise, just prior to the establishment of the CER. The Directives were published in November 2001 and covered gas transmission revenues and charges for the onshore transmission network, the Scotland to Ireland interconnector and the Inch entry/exit point. The CER used the charges formula established by the Ministerial Directive to review tariffs and charges for the transmission system in 2002 and applied an annual change for the year starting October 2002 (the gas year runs from 1st October). A regulatory review of the charging regime for gas transmission and distribution was then undertaken for the four year period starting 1 October 2003.

In CER/02/83, the CER indicated that they would introduce model arrangements for TPA (e.g. clauses for TPA agreements) and that they would set out the framework for the standardisation of access terms and conditions. Third-party shippers agree terms with BGE using a Standard Transportation Agreement that deals with customer-specific issues such as location, reserved capacity (Maximum Daily Quantity/Maximum Hourly Quantity), pressure, ramp rates, notice periods, applicable balancing tolerances and applicable maintenance days at the Exit Point. This Agreement is part of the BGE Code of Operations that establishes detailed rules relating to ‘capacity, balancing, shrinkage, entry/exit points, nominations, allocations, measurement and testing, specifications, quality and pressure, system planning, maintenance, emergencies and throughput restrictions’20.


Ex ante price control regulation – Based on the UK RPI-X regime

An X of -2% was set at the 2003 review, allowing annual tariffs to increase by CPI+2%.


There are four yearly reviews for Transmission & Distribution revenues. While distribution revenues were fixed for the gas year starting 1 October 2004, a review of the structure of distribution tariffs is currently underway.

At present, there are annual reviews for supply tariffs.


There are separate revenue controls for gas transmission and distribution and a separate control for gas supply tariffs. There is no gas storage in Ireland at present, although it is open to third parties to construct gas storage facilities.

20 Arthur Cox (2004), ’Ireland’ in Global Competition Review (2004), Getting the Deal Through – Gas

Regulation 2004.

Annexe 6: Ireland



A building block approach is used to set the price control - Annual X-factor(s) is (are) determined to ensure that the net present value of revenues is sufficient to cover expected required costs.

A view is formed on the overall level of allowable revenue by considering the appropriate value of: the opening asset value; operating expenditure; depreciation; capital expenditure and the return allowed on assets (cost of capital). (see CER/03/172)


A revenue cap is used to control BGE’s transmission allowable revenue, placing a maximum on the amount of revenue in each year of the regulatory period. A separate revenue control formula is used for the onshore system, the two interconnectors and the Inch entry point to ensure that there is no cross-subsidisation between Inch and Moffat entry or exit tariffs.

The CER argues that a revenue control is appropriate as ‘the level of spare capacity within the Irish gas transmission system means that BGT’s costs are in large part invariant to the level of demand’. (see CER/03/172)

A correction factor is included in the control to allow for any over- or under-recovery of revenues. Under and over recoveries are adjusted in the revenue formula by the Euribor rate plus 2%. Over recoveries exceeding 3% of allowed annual revenues are adjusted by the Euribor plus 4%. Adjustments are also allowed through the correction factors if allowable revenues raised from entry and exit tariffs are reduced because other sources of revenues become available to BGT from the use of its assets (e.g. revenue from interconnection as a back-up to indigenous supplies). 50% of such unforeseen revenues are retained by BGT (as an incentive to develop new products) and the remainder are deducted from allowable revenues.


Set by CER as part of transmission charges review.

Under the existing tariff structure there are locational entry charges and a ‘postalised’ exit charge. The entry tariffs are based on the cost of the infrastructure required to input gas into the onshore system at each entry point. Exit tariffs are based on average costs of the onshore transmission system. The tariffs reflect a 90:10 capacity/commodity split.

This structure was retained in the 2003 review but the CER signalled at the time that there would be a review of charges for the 2007 price review which would include an assessment of whether a move to a marginal cost pricing system would be desirable and feasible.


The CER is in the process of moving from a notional path (point to point) capacity booking regime to an entry exit system. This is due to be implemented in April 2005.

Under the current Code of Operations an operator has to book capacity from entry point to exit point on the transmission system and ensure that capacities at entry and exit are matched, although shippers pay for entry and exit capacity separately. This is noted by the CER who state that ‘although shippers pay for entry and exit separately, they purchase capacity from ‘point to point’ through the system’ (See CER/02/83). That is, the capacity booking system retains a link to physical capacity, by insisting that shippers reserve Entry and Exit capacities that match. The distribution system capacity is really exit only (capacity comes bundled with the supply point).

Annexe 6: Ireland


BGE are in the process moving to a full entry/exit capacity booking regime, with a National Balancing Point to generalise the balancing of all entry and all exit points rather than focusing on specific locations. All entry and exit points will be treated equivalently in this regime.


See discussion above on the move to an entry-exit charging system.

A review of the structure of distribution charges is currently underway and may result in changes to the tariff structure from October 2005.

Changes to the revenue restraints agreed in 2003 may be implemented to take account of an accelerated programme of iron main replacement.

Any other information of interest on access arrangement and/or price restraints

In CER/03/172, CER allowed BGE to retain all the revenue under-recovery from 2002/03, except for 50% of the under-recovery that was associated with the closure of IFI (a major industrial customer). In this regard CER emphasised that it ‘did not consider it reasonable that customers alone should bear the consequences of the particular event of IFI’s closure’.

Table 46: Regulatory regime – Ireland

Annexe 6: Ireland



The discussion on the regulatory regime, and the setting of the RAB and the WACC, is based on the approach used by the CER in 2003 to set transmission tariffs for the period October 1st 2003 to September 30th 2007. Since this was the first formal regulatory review by the CER, no policy has been announced relating to the rolling forward of capital expenditure, efficiency incentives and the appropriate treatment of historical over or underspend.


Yes


An index approach is used for determining the allowed capital value.


The opening asset value was based on Indexed Historical Cost (IHC) of the assets. The inflation index used was the Irish Consumer Price Index (CPI) (see CER/03/172)


During the 2003 review CER consulted on five alternative approaches to valuing the opening value of BGE’s assets, including the use of replacement cost or optimised replacement cost values. Index Historical Cost was used because it was thought to be more objective (less subjective) and more stable than replacements cost methods, and would therefore result in less disputes and uncertainty. The CER also noted that the historical cost approach was used in other jurisdictions for setting regulated monopoly tariffs (see CER/03/144). In summary, ‘The Commission believes that IHC is both a more objective method for valuing assets and produces a more stable level of allowed revenues than replacement cost methods.’



Historic cost value of assets inflated by the Irish Consumer Price Index (CPI)


Assets associated with the onshore transmission system, interconnectors (existing and in construction) and the Inch entry point.


Some adjustments were made to the value of the asset base submitted by BGE to establish the opening regulatory asset value(see CER/03/172):

•

•

•

the net book value of the EU grant awarded for the interconnector with Scotland was reallocated from the Onshore system to the interconnector, reducing the asset base of the interconnector and increasing the asset base of the onshore system;

the asset base of the onshore system was increased to reflect the CER’s position on the most appropriate method for allocating BGE buildings between transmission, distribution and supply; and

the asset base of the onshore system was reduced to allow for the asset value associated with Aurora, BGE’s telecommunications business.

Value at September 2003

Annexe 6: Ireland



None specified


CER was interested in ensuring stable revenues and using an approach that is objective.


Book value of assets provided by BGE. These were inflated using the Irish CPI. Adjustments were made to the valuation provided by BGE (as noted above) and involved discussions and negotiations with the company. As noted below, there were also differences in the asset lives proposed by BGE and those used by the CER and hence in the depreciation profile used for the asset valuation.


A straight line accounting depreciation rule is used

The standard depreciation rule applies to assets associated with the Inch entry point, the first interconnector with Scotland (including the associated grant) and the majority of the onshore system assets.

Depreciation of the pipeline to the west and a proportion of the interconnectors (the proportion of total interconnector assets equal to the asset value for the second Scottish interconnector) was deferred because of expected under-utilisation during the control period. Instead of the standard rule used for other assets a 1% per annum straight line rate was used for these assets CER argued that this provided a proxy for a profile depreciation rate based on expected usage of these assets. All new capital expenditure on assets with a life less than 5 -years (including on the pipeline to the west and the interconnectors) are depreciated using the straight-line rule. The decision on annual rate of depreciation was noted as an issue to be reviewed further at the next regulatory review (see CER/03/172).


Based on asset lives of 50 years for pipelines (higher than BGT proposed asset life of 40 years), 25 years for compressor stations (higher than BGT proposed asset life of 20 years), and 40 years for above Ground Installations (AGIs) (as per BGT approach). Assets such as IT equipment are assumed to have a 5-year asset life. The CER’s decisions on appropriate asset lives were based on work undertaken by engineers to assess the design, technical and economic life of the regulated assets.

How is the opening value rolled forward for the regulatory period?

The RAB in each year of the regulatory period is equal to the book value of assets in the previous year rolled forward by expected capital investment, less expected withdrawals and expected depreciation, to give a closing value of the RAB for that year. In each year assets are rolled forward by the Irish Harmonised Consumer Price Index (HCPI), which is expected to best reflect the actual change in BGT’s real costs. The same index is used for both rolling forward the RAB and the calculation of the WACC to insure consistency. (see CER/03/172). However, a different index – the Irish consumer price index – is used to determine the initial value of the RAB.

As there has only been one review it is not certain how the RAB will be rolled forward in future regulatory periods. It looks likely that the approach used in the UK will be adopted – i.e. roll forward historical RAB by actual additions less depreciation.

The value of the RAB for the current price control period is shown in Table 48.


Will be reviewed at next regulatory review but no known changes at this stage

Table 47: Methodology used to calculate the RAB - Ireland

Annexe 6: Ireland


€m 2003/04 2004/05 2005/06 2006/07

Opening asset value

779.22 806.56 800.51 794.08

Depreciation 20.56 19.95 19.97 20.25

Investment 47.91 13.89 13.53 13.16

Closing asset value

806.56 800.51 794.08 786.99

Table 48: BGE's allowed regulatory capital value for Onshore Transmission Assets

Source: CER (2003), Commission's Decision on Transmission Use of System Revenue Requirement and Tariff Structure


A distinction is made between capital investment for the construction of a transmission pipeline that is subject to a regulatory consent requirement and capital investment that are not subject to consent. Only investment that is not subject to consent is included in the calculation of allowed revenues. A separate incentive system – based on setting a target construction cost for each new pipeline – is used for the building of new pipeline that is subject to consent (See CER/03/060).

A distinction is made between growth, non-growth and indirect non-growth capital costs. Capital expenditure is broken down into the main capital asset categories of BGE (i.e. onshore system, Inch entry point, Interconnector 1, Interconnector 2).

Allowed revenue is calculated using expected capital expenditure requirements.

BGE provided a proposal of its capital expenditure requirements for the transmission business for the regulatory period. This was reviewed and adjusted by the CER to ensure that the proposed investment levels are ‘reasonable’ given expected demand, customer growth and market developments (see CER/03/144).

The main adjustments made by CER to BGE’s forecasts for the 2003 review were:

•

• •

a reduction was made to growth and non-growth capital expenditure to reflect advice from engineering consultants on the scope for ongoing efficiency improvements;

investment relating to a delayed project was removed;

capital expenditure relating to connections was reduced by 25% to reflect a new connections policy whereby the regulator required a varying proportion of the costs to be recovered directly from the customer.

CER note that ‘all pipeline-related capital expenditures will be subject to rigorous examination under the section 39A consents process as applicable’ (see CER/03/172).

CER consultation documents for the 2003 review suggest that expenditure which is deemed ‘reasonable’ or ‘prudent’ by the regulator is allowed in the calculation of revenues. There is no definition given for these terms, however, and no indication of how the CER decides what is ‘reasonable’ or ‘prudent’. A process of consultation with the

Annexe 6: Ireland


company appears to be undertaken however.


Replacement investment was not considered at the time of the last review – subsequently significant replacement expenditure has been undertaken.


No history


No history


No history


Not clear which items qualify for inclusion in the RAB


No.

Any other information of interest on treatment of capital investment

Iron mains replacement expenditure was not included in the last price review but is likely to be considered at the next review given the levels of expenditure since undertaken by the company.

Table 49: Treatment of capital expenditure in the RAB - Ireland

Annexe 6: Ireland




Table 3.1 in CER/03/172 suggests that a CAPM model was used to inform the CER of the appropriate WACC. This method was chosen because it was widely used and therefore generally understood (see CER/03/144)

CER’s decision on the WACC has not been transparent, with very little justification provided for each element of the CAPM calculation. NERA produced a report for the regulator on the appropriate cost of capital but the value used by CER was lower than that suggested (with no explanation). We present both CER’s assumptions and NERA’s suggested best estimates here.


The risk free rate

A real risk free rate of 2.5% was used (4.5% nominal). The rate suggested by NERA was the same (4.48%).

The beta

An asset beta of 0.4 was assumed, which translated into an equity beta of 0.9 given the CER’s assumptions on gearing. The CER emphasised that the asset beta of 0.4 was consistent with estimated betas for British Gas (before Lattice was demerged) and Gas Natural (Spain). It was also consistent with the assumptions made by Ofgem for NGC in 2000 and Transco in 2001, and with the CER’s own assumption for electricity transmission.

NERA’s proposed rate of 0.45 for the asset beta was similar but resulted in a slightly higher equity beta of 1.00.

Equity risk premium

An equity risk premium of 5% was used. NERA proposed a higher value of 6%.


The cost of debt is calculated as the real risk free rate plus the debt premium (including issuance costs). The debt premium was set at 1.4%, giving a real cost of debt of 3.9%. The cost of debt proposed by NERA was the same (3.91%).


The level of gearing used was 55% (debt over debt plus equity). The associated leverage rate (debt over equity) is 1.22. This appears to be an assumed optimal gearing level, as the CER argued in CER/03/060 that it was minded to use such an approach when calculating the WACC.

NERA proposed the same gearing and leverage rates.


CER adjusted the real pre-tax cost of equity to a post-tax value using a tax shield of 12.5%. The same approach was proposed by NERA. Although not stated by CER, this is expected to be consistent with BGT’s corporation tax rate.


When discussing the asset beta value the CER used comparisons with decisions made

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for electricity transmission in Ireland and for gas and electricity transmission in the UK. Presumably comparators were needed here because of the problems associated with estimating a beta for a publicly owned company. The CER does not specify whether or not comparisons were used to determine other elements of the CAPM model.


A real pre-tax WACC of 5.74% (5% post-tax) was used by CER to set current tariffs. This was lower than the 6.5% recommended by NERA in their research report for CER.

NERA proposed a real pre-tax WACC of 6.54% (primarily reflecting the higher assumption on the equity risk premium). This is equivalent to a post-tax WACC of 5.72% and a real vanilla WACC of 5.99%.


None specified at this stage

Table 50: Determination of the WACC – Ireland

INFORMATION SOURCES


• www.bordgais.ie


• www.cer.ie

•

•

• • •

•

•

CER (2003), Commission’s Decision on Transmission Use of System Revenue Requirement and Tariff Structure 1October 2003-30 September 2007, July (CER/03/172)

CER (2003), Commission’s Proposals on Transmission Use of System Revenue Requirement and Tariff Structure 1October 2003-30 September 2007, June (CER/03/144)

CER (2003), Transmission and Distribution Tariffs Objectives and Principles, March (CER/03/060)

CER (2002), Natural Gas Policy Framework, July (CER/02/83)

NERA (2003), BGE’s Cost of Capital – A Final Report for the Commission for Energy Regulation, June


Gas (Interim) (Regulation) Act 2002

Other


Annexe 6: Ireland


http://www.creg.be/


Annexe 7: Italy




High-pressure (transmission) pipelines are owned by:

1) Snam Rete Gas (SRG), over 90% of the total network

2) Edison T&S, and

3) SGM

All the cross-border interconnection pipelines belong to SRG


All companies are privately owned.

1) The Snam Rete Gas share capital prior to the IPO (December 6th 2002) was 100% in the hands of Snam (Eni Group). After the placement Snam has 59.8% of the capital, with the market holding the rest. The market share is divided between 8% in the hands of private investors and 32% held by institutional investors. Foreign investors make up 80% of institutional investors with Italian ones making up the rest. Of the private investors, Snam Rete Gas employees hold 0.2% of the capital while Eni shareholders possess more than 2%.

2) Until very recently both Edison T&S and SGM belonged to Edison. On September 7th, 2004 Edison completed the sale of its gas transmission operations to an Italian private equity fund managed by Clessidra Sgr. Edison transferred 100% of Edison T&S and 83.34% of its SGM subsidiary to the buyer.


Two out of the three transportation companies are parts of larger corporate groups:

1) SRG is a subsidiary of ENI – the main national producer of natural gas, as well as one of the 8 importing companies;

2) Until September 7th, 2004 Edison T&S and SGM were part of Edison – second largest domestic producer of natural gas, as well as one of the 8 importing companies. On that date, both companies were sold to an Italian private equity fund managed by Clessidra Sqr.


The Italian Regulatory Authority for Electricity and Gas and the Competition Authority have adopted policies aimed at strengthening the interconnection capacity via pipelines and LNG terminals. A joint investigation aimed at verifying the degree of competitiveness of the energy market, possible obstacles to increased competition and actions to remove such obstacles is to be completed shortly.

As of 1 July 2007, no entity active in the production, or importation, or distribution, or sale of natural gas, can own more than 20 per cent of companies that own and manage high-pressure natural gas transportation pipelines.

Table 51: Basic facts on GTS operator - Italy

Annexe 7: Italy



The pipelines of the national gas transportation system are 8,337 km long. Edison T&S and SGM own 1300 km, the rest belongs to SRG.

Maximum pressure in the system is 75 bar.


4 interconnectors:

a) Passo Gries (from Switzerland),

b) Tarvisio (from Austria),

c) Mazara del Vallo (from Tunisia), and

d) Gorizia (from Slovenia).

There is also an LNG terminal (Panigaglia).

The average booked capacity is at present very close to maximum capacity in all of the interconnection infrastructures.


An interconnection with Libya is to be completed shortly and will be linked to the national gas system in Gela, Sicily.

Table 52: Technical information on gas sector - Italy

Annexe 7: Italy




In May 2000, Legislative Decree 164/2000 (the Letta Decree) implemented the European directive for the liberalisation of the gas market, which involved major changes to many parts of the regulatory regime in the gas sector. In particular, the Decree split off natural gas transportation and dispatching from the other gas activities (such as purchasing supply and sales) by 1st January 2002.

In addition, the reform of the Italian constitution in 2001 has entitled regional governments to coordinate with the central government on policy-making for energy markets, which may lead to future developments in the statutory and regulatory framework of the gas sector.

No major steps are expected after the enforcement of EU Directive No. 03/55, since all of its major principles are already in force in the Italian gas market.


Authority for Electricity and Gas (AEG)

The Ministry of Productive Activities (MPA)

Regional governments

GTS operators (in part of drafting Network Codes)


The AEG is a fully independent regulator whose decision-making commissioners are appointed by the President of the Republic, upon the indication of the MPA and the approval of the government.

The MPA is in charge of issuing the provisions that affect the general framework of the gas system regulations, while the AEG is in charge of more detailed regulation, either independently and/or specifying the principles set forth by the MPA.

As the competence of the regions in energy production, transportation and distribution is concurrent with that of central authorities, this means that the regions will regulate these sectors within the framework set at national level.


Under law no. 481 of November 14th 1995 (Constitution of the Italian Regulatory Authority for Electricity and Gas), the main functions of the AEG with respect to prices and quality are:

1) Prices: To set basic tariffs for the regulated sectors. This includes maximum prices net of tax, and tariff adjustments based on a price-cap mechanism (defined as a "ceiling on price variations on a multi-annual basis"). The price-cap mechanism sets a limit on annual tariff increases corresponding to the difference between the target inflation rate and the increased productivity attainable by the service provider, along with any other factors allowed for in the tariff, such as quality improvements.

2) Quality: To establish guidelines for the production and distribution of services, as well as specific and overall service standards and automatic refund mechanisms for users and consumers in cases where standards are not met. To monitor quality standards set by the Authority, and the adoption and application of the Citizens' Service Charter. Quality standards may refer to both the terms

Annexe 7: Italy


and conditions of contracts (such as response time to calls or complaints) and technical aspects of the service (such as service continuity and safety).


Ministerial Decrees and the AEG’s regulations can be appealed before the administrative courts (respectively of Lazio and Lombardy).


Court of law


The Competition Authority has recently started an investigation on ENI for violation of its duty to increase gas transportation capacity on the import interconnectors. That duty was, in fact, imposed in 2002 as a commitment on ENI at the end of an investigation of the same Competition Authority, whereby the ENI group had been found to have abused its dominant position in the management of the access to the interconnection capacity.


None known

Table 53: Regulatory institutions - Italy

Annexe 7: Italy



Each transportation company drafts a network code where rules for the operation of the pipelines each respectively owns and manages are defined. Such rules must comply with the principles set forth by the AEG in Regulation No. 137/02 and compliance is verified by the AEG, which can approve or modify network codes. These are enforced as of the publication on the AEG’s website. There are only two codes, because Edison T&S and SGM have a single code. Access to storage fields will be subject to the rules provided in the Storage Codes, still to be issued; in the meantime access rules have been provided with AEG’s resolutions.

Natural gas transport and mining, strategic and modulation storage are deemed to be activities of public interest and the respective services are to be provided on a non-discriminatory basis to any requesting entities. However, interconnection and provision of storage are mandatory only if technically and economically feasible.

In the event of unjustified refusal of interconnection or provision of storage services, the AEG – having heard the transportation company – can order that the requested interconnection of storage service is made or provided. The powers of AEG do not preclude the competencies of the Competition Authority in this field (i.e., possible abuse of a dominant position).

Access to the national gas system must be granted for any quantity of natural gas, unless there is no available capacity. Access can be denied even if the grant would prevent transport companies from fulfilling their public service duties, or if the said transport capacity is necessary to transport natural gas purchased under take-or-pay agreements entered into before the implementation of the EU Gas Directive.

These rules apply for the access through entry points from abroad, while access in the domestic system, in case of lack of capacity, is made pro quota. Access and storage can never be denied to domestically produced natural gas. Refusal of access must be explicit and shall be communicated by the transport company to the AEG, the Competition Authority, and MPA.

Should the refusal of access to gas pipelines derive from financial unfeasibility, the party that requested the access can finance on its own new facilities, and will obtain a priority right to use up to 80 per cent of the new interconnection capacity for 20 years.

Access to the national gas system is given in the following order of priority to:

1) gas sale and purchase agreements with a take-or-pay clause entered into before 10 August 1998 (up to the average daily quantity);

2) multi-annual gas import agreements (up to the average daily quantity);

3) annual gas import agreements and agreements under points one and two above (for the difference between the maximum daily quantity and the average daily quantity); and

4) other supply agreements.

The access capacity is granted in the above order up to five thermal years for multi-annual agreements, and up to one thermal year in other cases.

Priority is also given for merchant pipelines to relevant financiers.

Priority in accessing storage facilities is giving to mining storage of domestic natural gas production. Strategic storage is a duty of gas importers, while traders are in charge of modulation storage.

Gas companies that have been granted transportation capacity can transfer it to other gas companies or end-users (cessione di capacita). If an end-user changes supplier, the new supplier is entitled to request the former to transfer the transport capacity, that was available to it, in order to supply the end-user that switched supplier (transferimento di capacita).

Annexe 7: Italy



The AEG updates the allowed revenue to be earned from transportation charges each year, using a framework that is fixed for a four year period. The allowed revenue in year n of the four-year period is calculated as the initial value of the assets, rolled forward by inflation, plus the allowed value of investment undertaken since the start of the period (net of depreciation) rolled forward by inflation.

New investments can only be recognised in the tariff if economically justifiable. If a user has contributed financially to the expansion of a transportation pipeline, it will have title to a return on the investment made at least equal to an annual 7.94% of the sum paid, in terms of a discounted unitary transportation tariff.


4 year regulatory period (current regulatory period from 1 October 2002 to 30 September 2005).

Tariffs are assessed on an annual basis (given the methodology determined at the regulatory review every four years).

Transport and storage tariff principles are defined by the AEG for each regulatory period, and AEG then approves the tariffs to be applied in each year.


Gas transportation only.

Methodology used to set the price control (please describe, particularly if non-standard)

Building block approach - transportation companies report to AEG their allowed operating and capital costs (book values, according to rules set by the AEG). These are used to obtain solutions to tariff formulas (which include other parameters as well, such as utilisation and capacity) which are consistent with the regulator’s decision about the allowed rate of return on capital.


Revenue control


Transport tariffs are based on an entry-exit mechanism, based on the booked capacity at entry points (borders, production fields, and storages) and at exit points (connection to the 15 regional grids), as well as on a stamp duty applied on the capacity booked on the regional grids. In parallel, a variable fee is applied for the gas quantities effectively injected and off taken from the system.


Entry-exit, plus capacity, plus volume (see above)


None known

Table 54: Regulatory regime - Italy

Annexe 7: Italy




Yes - an initial RAB is calculated for determining allowed revenues. The allowed value of new investment (which appears to be an allowed return on the new investment) is then added to the return on this initial value (indexed to current prices) to calculate updated allowed revenues.


See above - a non-standard index approach is used as it is the allowed revenue formula which is updated by new investment rather than the RAB value itself.


Limited information provided but indication is that regulator’s main objective is to ensure that companies are provided with incentive to undertake required investment by ensuring that adequate recovery of investment is assured in the tariff-setting process.


An adjusted indexed historic cost approach is used to calculate the initial value of the RAB.

At the time of issuance of the guidance document for the price control (2001, amended 2002) each company carrying out transportation activities had to conduct a revaluation of its fixed assets, according to the following rules.

a) Calculate the annual increases in the value of the assets posted in the financial statements at 31 December 2000. These increases were grouped into the following categories: buildings, pipes, compressor stations, and other fixed assets (for the purposes of useful life assignment), and exclude interest paid for work in progress that is not included in the financial statements.

b) Revalue the historical cost of these value increases using the gross fixed investment deflator set out in the price control guidance document.

c) Calculate the gross invested capital for each category of fixed assets as the sum of the values resulting from individual revaluations.

d) Determine the accumulated economic-technical amortisation deriving from the sum of the products of the individual value increases (a) by the respective deterioration rates as defined below:

PD = (2000-AIP)/VUT x 100, where

AIP is the year of the value increase, and

VUT is the useful life for a given asset category (land is not subject to amortisation)

e) Calculate, in relation to the useful life of the assets, the percentage of government subsidies received for the development of natural gas transportation infrastructure that is attributable to each year, again adjusted by the gross fixed investment deflator for that year.

f) Calculate the net value of the assets by subtracting from the gross invested capital (c) the accumulated economical-technical amortisation (d) and total subsidies (e).


Indication given by regulator is that this methodology was chosen to ensure the initial

Annexe 7: Italy


value closely reflected the current cost value of the assets.


31st December 2000


Indexed HCA


Assets included in financial statements


Historic cost of assets revalued using a gross fixed investment inflator specified by the regulator.

Adjustment made to remove the real value of government subsidies received for gas transportation infrastructure.


None specified


Ensure that incentives for capital investment are strong.


Values taken from financial accounts and adjustments made as explained above. Approach seems to be quite mechanistic and was undertaken by the companies following guidelines from AEG.


Straight-line depreciation, based on useful life by category of assets, as set by the AEG.


Pipelines - 40 years

Compressor stations - 20 years

Buildings - 50 years

Other fixed assets - 10 years


The initial value of the RAB is rolled forward by an inflation index, which is not specified but is expected to be a consumer price index.

New investment is included in the calculation of allowed revenues and is not rolled forward in the initial value of the RAB. The value of new investment used in the calculation of allowed revenues is the depreciated book value (inflated for years between 2002 and the current year) times the allowed returns on investments.


None known

Table 55: Methodology used to calculate the RAB - Italy


Annexe 7: Italy



The net invested capital of transportation activities is defined as the net fixed assets calculated according to the formulas set by AEG, assuming the net working capital to be zero.


No


New investments are allowed for on the same conditions as those used to determine the initial value, providing that the investments are compatible with the efficiency and security of the system and comply with commercial criteria.


The test used is not clear but there is an expectation that investments should be efficient.


Allowed revenue is updated annually to reflect actual investment in the previous year – the incentive to make cost savings generally associated with a price cap regime is therefore dulled somewhat here.


Only assets that are in operation are included in the calculation of allowed revenues.


None known

Table 56: Treatment of capital expenditure in the RAB – Italy

Annexe 7: Italy




The CAPM model is used to calculate the cost of equity. Methodology details not available.


Real pre-tax WACC of 7.94% was used in 2001. This was fixed for four years and will be reviewed at the next review of the regulatory methodology.


None known

Table 57: Determination of the WACC – Italy

INFORMATION SOURCES


• http://www.snamretegas.it/english/

• http://www.edison.it/english/


• http://www.autorita.energia.it/inglese/

•

• • •

•

•

•

AEG (2002), Terms and conditions for the allocation of transmission capacity for the import, export and transit of electricity over the national transmission grid at the northern electricity border for 2003 (Decision n. 190/02)

AEG (2002), Norms to secure free access to natural gas transportation services and draw up network codes (Decision n. 137/02)

AEG (2002), Rules for setting tariffs for the storage of natural gas (Decision n. 26/02)

AEG (2002) Criteria for the setting of tariffs for the transportation and dispatching of natural gas and the use of LNG terminals (Decision n. 120/01 as amended by Decision n. 127/2002)

Information provided in conversations with contacts at AEG

Legislation

May 2000, Legislative Decree 164/2000 (the Letta Decree)

Other


Annexe 7: Italy


http://www.snamretegas.it/english/

http://www.edison.it/english/

http://www.autorita.energia.it/inglese/


Annexe 8: Spain




ENAGAS SA (the main transmission company)

Naturcorp group (operates in the Basque region in northern Spain)


Part public/part private

During 2000 Gas Natural SDG, former owner of the whole ENAGAS stock capital, was required to sell 65 % of its shares to institutional and private investors. BP has bought 5% of the capital. In 2003, a new law was introduced which obliged Gas Natural to sell the remaining shares by 2007. Any private company was only allowed to own 5% of shares after this date. In the interim, a company can own more than 5% of stock but can only have 5% of decision rights (i.e. votes).


Apart from gas transmission, ENAGAS is involved in:

• • •

regasification (operates three of the four regasification plants in Spain),

underground storage (owns the Serrablo storage facility in Huesca, and manages the Gaviota off-shore platform in Vizcaya), and

purchase and sale of natural gas (for the tariff market only – 20% of total market).

The various owners of ENAGAS are involved in other activities (e.g. BP has a number of interests outside the Spanish gas transmission sector).

Naturcorp is a group of energy-related companies in Spain and Portugal. The gas transportation business in the Basque region is one of them.


See the “ownership” section for further changes in ENAGAS ownership

Table 58: Basic facts on GTS operator - Spain

Annexe 8: Spain



6,522 km of high-pressure transportation pipelines (both primary network - 60 bars or more, and secondary network - 16-60 bars)

31,000 km of distribution pipelines (maximum design pressure of less than 16 bars, and any others, regardless of their maximum design pressure, whose purpose is to convey gas to a single consumer, starting off from a gas pipeline in the basic or secondary transportation network)


4 interconnectors:

Badajoz and Tuy (Portugal), Col de Larrau (France), and Tarifa (Morocco)


The construction of the new LNG terminal in the Bilbao’s harbour has been completed recently; two other LNG plants in Sagunto in the Mediterranean coast and Mugardos in the Atlantic North West coast continue their works of construction and are planned to start operations in 2005. A new interconnector with France has also recently been opened at Irun.

Table 59: Technical information on gas sector - Spain

Annexe 8: Spain




Current legislation and regulation originates from the implementation of the EU Gas Directive (1998), which was done by the Hydrocarbons Sector Law (Ley del Sector de Hidrocarburos, LSH) of the same year.

A Royal Decree of 2000 modified the law and provides that the transportation company owning the majority of the basic natural gas network is responsible for the technical management of the gas system in Spain, and appoints Enagas as the system technical manager.


CNE (Comision Nacional de Energia, National Energy Commission)

Ministry of Economy


The CNE is a public body with its own legal responsibility and full capacity to act.

The Commission is governed by the provisions of the Hydrocarbons Act 34/1998, dated October 7th, and by the legislation developing it, by any of the provisions of the Budget Act that may apply to it and by Act 6/1997, dated April 14th, on the Organisation and Functioning of the Central State Administration.

The members of the CNE Board of Commissioners, a collegiate body, are chosen from among individuals with acknowledged technical and professional ability and appointed by the Government, on the proposal of the Minister of Industry and Energy, following a debate within the relevant Committee in the Congress of Deputies (Lower House of Parliament). The Commissioners are appointed for a six-year term and may not perform any professional activity related to any energy sector for the two years subsequent to their giving up their seat on the Board.

The economic and financial control of the National Energy Commission is undertaken by the State Controller’s Office without prejudice to any functions that are the responsibility of the National Audit Office.

Control over performance of the CNE is undertaken by the Ministry of Economy. The CNE must prepare annual and quarterly follow-up reports about its performance for regular submission to the Ministry of Economy.


The government (Ministry of Economy) is responsible for:

a) Determining the rates charged for the use of facilities under third party access entitlement in those cases as may be stipulated by the Act and for setting the supply types and prices

b) Laying down the minimum quality and security requirements to govern the supply of hydrocarbons

The Ministry drafts the tariff proposals and sends them to CNE for comments. CNE comments in this consultation round are not legally binding and the final decision rests with the Ministry.

At the request of the Central State Administration or the Autonomous Regions with authority to do so, or ex officio, the CNE inspects:

Annexe 8: Spain


• • • • • • • • •

the technical conditions of installations;

compliance with the requirements stipulated in authorisations;

right use of the domestic coal as a fuel in the power plants eligible of subsidies;

the economic conditions and activities of the agents insofar as they may affect the application of tariffs and the criteria for remuneration of energy activities;

the availability of power plants under the ordinary regime;

billing and sale conditions to eligible consumers by distributors and suppliers;

the reliability of the supply;

the quality of the supply; and

the effective unbundling of these activities whenever this is required.

In addition, the CNE may carry out any checks it deems necessary in order to confirm the accuracy of the information furnished to it in compliance with its Circulars.


CNE

Ministry of Economy

Audiencia Nacional (a Spanish tribunal with national jurisdiction)


CNE settles any disputes that may be submitted to it concerning contracts for third party access to transmission networks and, as the case may be, distribution networks, on the statutory terms set out in regulations.

Any decisions adopted by the CNE when performing the function of settling any disputes concerning the economic and technical management of the system and transmission, in the case of the electricity industry and concerning the system management in the case of the gas industry, as well as any informative circulars, will bring the administrative appeals process to an end. Consequently, legal remedies may only be taken up under contentious-administrative jurisdiction.

An ordinary appeal may be lodged to the Minister of Economy against any other decisions adopted by the National Energy Commission and against any of the Commission’s acts when dealing with the same subjects.

Decisions of the Ministry of Economy can be challenged before the Audiencia Nacional (a Spanish tribunal with national jurisdiction).


None known


None known

Table 60: Regulatory institutions – Spain

Annexe 8: Spain



Royal Decree 949/2001 sets out the conditions for third-party access to the natural gas network.

Access is granted on a “first-come, first-serve” basis. Owners of transmission facilities who have received a capacity booking have a maximum period of 24 days to provide a response. In the event that access is denied, notification should be made to the soliciting party, the Ministry of Economy and the CNE. Access may be denied only in the following cases: a) lack of capacity; b) lack of reciprocity with an EU Member State; c) serious financial or economic difficulties arising from the execution of agreements containing “take-or-pay” clauses.


Ex ante cost plus regulation - annual allowed revenues are calculated using formulas set by the Ministry to ensure that annual new operating and capital investment costs are remunerated and to ensure that a return is earned on the value of assets that existed prior to the introduction of regulated TPA.

The tolls and fees for third parties access to the gas systems are set by Ministerial Order and are amended annually or whenever anything happens in the system that makes their amendment advisable.

The remuneration of regulated activities (charged to the tariffs, tolls and fees) is meant to:

a) Ensure the recovery of the investments made by the owners in the period of their useful life;

b) Allow for reasonable return on the financial resources invested; and

c) Determine the system for remunerating operating costs in such a way that incentives are offered for efficient management and productivity improvement that must be partly passed on to users and consumers.


Tariffs are revised annually, using the updating system specifed in the Ministerial Order.

The updating systems for remuneration are set for periods of four years. In the last year of validity of the remuneration system, it is revised and brought into line, as the case may be, with the system envisaged for the next period.

Then, following a report from NEC and before January 31st each year, the Ministry of Economy sets the fixed costs to remunerate each company or group of companies for that year, together with the specific values of the parameters for the calculation of the variable part that corresponds to them.


Regasification, storage and transportation. The remuneration of regasification, storage and transportation activities is calculated for each installation on an individualised basis.


Allowed revenues in year n are calculated as the sum of:

• allowed revenues that relate to assets that were operating on 31st December 2001 (inflated to year n prices);

Annexe 8: Spain


• •

•

allowed revenues that relate to new investments that came into operation since 31st December 2001 (inflated to year n prices); and

allowed revenues that relate to variable cost for regasification (inflated to year n prices); and

allowed revenues that relate to operating expenditure.

We therefore have a rolling allowed revenue calculation rather than a rolling asset value, but the underlying parameters considered are the same.


Revenue control


The maximum tolls and fees for third parties access to the gas systems are set by Ministerial Order and are amended annually or whenever anything happens in the system that makes their amendment advisable. These tariffs are the same tariffs for the whole country in line with the volume, pressure and method of consumption.

Transportation and distribution toll: This toll includes the right to use the necessary facilities to transport the gas from the point of entry to the transportation network to the point of supply to the qualified consumer, as well as the use of an operating storage corresponding to 5 days of the contracted transportation and distribution capacity (2 days since February 2005). It is also charged for the supply of qualified consumers connected to the local distribution networks supplied through satellite plants. The transportation and distribution toll is made up of a capacity reserve component and a pipe conveyance component (Tc).

The transportation and distribution capacity reserve component will be billed by the transportation company that is the titleholder of the installations wherever the point of entry of natural gas to the transportation and distribution system is located.

The pipe conveyance component will be billed by the distribution company that is the titleholder of the installations where the point of delivery of natural gas to the final consumer is located, to the agent with an access contract. The pipe conveyance component of the natural gas transportation and distribution toll is structured according to the different pressure levels.


Uniform tariff (see the description above)


None known

Table 61: Regulatory regime - Spain

Annexe 8: Spain




The regulator calculates allowed revenues that relate to assets that were operating on 31st December 2001 (inflated to year n prices). This is similar to an initial asset value.


The value of allowed revenues that relate to assets that were operating on 31st December 2001 (inflated to year n prices) was calculated by the Ministry and the methodology used is not public.

This initial value is rolled forward by inflation (see details below).

The allowed revenues each year are rolled forward to allow for new investments to be remunerated through transportation charges. These new investment values are not included in the RAB however.


The methodology is set by the Ministry and the rationale is not publicly available.


The Ministry set the value of allowed revenues that relate to assets that were operating on 31st December 2001 to reflect the fixed cost acknowledged in year 2002 for the regasification, storage and transportation facilities that entered into service before December 31st 2001. Details of how this initial valuation was undertaken are not publicly available.


The value of allowed revenues that relate to assets that were operating on 31st December 2001 was set by the Ministry and the rationale for the methodology used is not publicly available.


December 31 2001


Not publicly available.


All regasification, storage and transportation facilities that entered into service by December 31st 2001.


Not known as methodology is not public






Straight-line, based on the assumed (according to rules set by the Ministry) useful life

Annexe 8: Spain



Assets that have ended their economic life and which are not in operation are removed from the allowed revenue calculation.

Assets that have ended their economic life but continue operating are included in the allowed revenue calculation. All of the associated operating expenditure is included and 50% of the allowed return on the investment.


The asset life assumptions used for the gas pipelines business are: 30 years for gas pipelines; 20 years for compression stations; and 30 years for regulation and measurement facilities.

The asset life assumptions used for regasification plants are: 50 years for infrastructures on land and at sea; 20 years for storage tanks; 10 years for regasification facilities; and 20 years for tanker loaders.


The value of allowed revenue that relates to assets that were operational prior to 31st December 2001 are rolled forward by inflation each year. The formal definition of the inflation index is as follows:

Ij = (1 + IPHj x fj), where:

IPHj is forecast of the change in index for year j, calculated as:

IPHj = (IPCj + IPRIj)/2, where:

IPCj is the forecast of the change in the consumer price index for the year j, and

IPRIj is the forecast of the change in the industrial price index for the year j

fj is the efficiency index for year j, which may not exceed 0.85.

For previous years, the final values of the official consumer price index (IPC) and the official industrial price index (IPRI), available at the time of calculation, are used in this formula. For years n-1 and n, the values of which are unknown when the regasification, storage and transportation costs of year n are determined, the estimate made by the Government in its draft General State Budget for year n and the estimated IPRI are applied.

Allowed revenue in each year also includes a value relating to investments undertaken since 31st December 2001. A number of different investment types are distinguished - most notably those that are authorized by tender and those that are directly authorized. For the former the investment value is the fixed cost included in the tender contract. For directly authorized investments the value is equal to the depreciation charge (reflecting the year that the assets became operational) plus a return on the value of the investment as calculated in the year that the assets became operational. This value is calculated on a replacement cost basis using unit prices set by the Ministry. The calculated depreciation charge and return on the value of investment are rolled forward each year by the same inflation index as is used on the initial allowed revenue element.

The precise valuation rules for the investments are as follows:

CIT(n) = A(n) + R(n), where

CIT(n) is the annual investment cost of a new directly-authorised regasification, storage or transportation facility in year n, which was commissioned in year n-1;

Annexe 8: Spain


A(n) is annual depreciation cost, calculated as:

A(n) = VAI(n)/VU, where

VAI(n) is value of the investment in year n, which is calculated by applying unit values set by the Ministry to the physical units of the new facility; and

VU is useful life of the facilities (also set by the ministry based on type of installation, e.g. 30 years for gas pipelines, and 20 years for compression stations).

R(n) is the annual cost of remuneration for the investment, calculated as:

R(n) = VAI(n) x Trn, where

Trn is the rate of remuneration of the investment in year n (see below the section on WACC).

The Ministry of Economy sets a specific valuation for those installations authorised directly that have unusual technical characteristics.

Any investments that entail modifications of existing installations providing that such modifications lead to an increase in the capacity of that installation are dealt with in the same way.


None known

Table 62: Methodology used to calculate the RAB - Spain


Annexe 8: Spain



The law operates with the concept “fixed costs”, but gives no specific definition of those.


No


All investments appear to be included, with valuation based on Ministry formula outlined above.


None known


Tariffs are adjusted annually to reflect actual investment so efficiency incentives are expected to be limited.


Transportation companies owning regasification, storage and transportation facilities which became operational after December 1st of year n-1 and which therefore have not been included in the cost accredited in year n, may ask the Directorate General for Energy Policy and Mines for their inclusion in the remuneration regime provided that they fulfil the following requirements:

a) They have a certificate, issued by the competent authority, confirming that they are operational;

b) The company expressly included them in the forecasts of new facilities submitted prior to last review.

The Directorate takes a decision on this request, expressly indicating the date as of which the facilities shall be included in the remuneration regime.


None known

Table 63: Treatment of capital expenditure in the RAB – Spain

Annexe 8: Spain




See the WACC section below


See the WACC section below


According to Order ECO/79/2002, “The rate of remuneration of the annual investment to be applied shall be the annual average of 10-year Government bonds or the interest rate that replaces it, plus 1.5 per cent”. There is no distinction between cost of equity and cost of debt.


None known

Table 64: Determination of the WACC - Spain

INFORMATION SOURCES


• http://www.enagas.es/index.jsp

• •

•

Enagas (2003), Higher Growth and Value - corporate brochure, June 2003

Enagas (2003), Annual Report, 2003


http://www.cne.es

•

• • • • •

CNE (2004), Chronology of Spain's National Energy Regulatory Commission (CNE): 1998-2003. Department of External Relations and Information Services. Ref.: IAP CHRONOLOGY CNE

CNE (2004), Legislation Development of the Spanish Hydrocarbon Act (Unofficial English Translation), Volume 2,

CNE (2002), National Energy Commission Bye-Laws. 2nd edition, revised and updated. Ref.: NE_RCNEI

CNE (2002), Gas Tariffs and Tolls (TPA tariffs)

CNE(2000), National Energy Commission: Informative Brochure. Ref.: NE 003/00

Information provided in conversations with contacts at CNE

Annexe 8: Spain

http://www.enagas.es/index.jsp

http://www./


Legislation

• • •

•

Royal Decree 949/2001

Hydrocarbons Act. 2nd edition (2002), revised and updated. Ref.: NE_LHI on CNE website

Ministerial Order ECO/32/2004 (on CNE website)

Other


Annexe 8: Spain


Annexe 9: UK




National Grid Transco (NGT)

British Gas was privatised in 1986 as a vertically integrated company with a local monopoly over all customers under 25,000 therms p.a.. The Gas Act of 1995 required full separation of transportation & supply activities. This was implemented in February 1997 with the demerger of British Gas into two companies - BG plc and Centrica (the supply company). Transco was part of BG plc and had responsibility for the network, storage/LNG, and connections businesses. In December 1999 Transco became a plc, BG Transco plc and in October 2000 it demerged from BG plc and became part of the Lattice Group. In 2002 Lattice Group merged with the National Grid Group (the electricity transmission company) and formed National Grid Transco plc.


Private

Government retained a ‘golden share’ at privatisation but redeemed it in 2004.


Yes. NGT also owns NGC (the high voltage electricity transmission network) and infrastructure assets (primarily in the electricity sector) in North and South America, Australia, India and Zambia.

NGT includes the National Transmission System (NTS) and eight regional distribution networks (RDNs). Four of the eight RDNs have recently been agreed for sale to other private companies. For the other four, NGT has indicated it plans to retain them at present.

In addition to its transportation responsibility, Transco’s system control centre operates and balances gas flows on all of the gas network.


In April 2002 Transco reorganised its 12 Local Distribution Zones (LDZs) into eight regional distribution networks (RDNs). Transco plans to demerge some RDNs and sell them to other infrastructure operators. This will involve substantial regulatory changes (in particular, there will be separate gas distribution price controls, and Ofgem will be able to compare relative efficiencies of different private operators).

Table 65: Basic facts on GTS operator - UK

Annexe 9: UK



National transmission system (NTS) is the high pressure system and operates at up to 85 bar. The NTS supplies gas to 12 local distribution zones (LDZs) which are based within eight regional distribution networks (RDNs) for management purposes. Four of the eight RDNs have recently been agreed for private sale.

Total network (both high pressure and distribution) is 270,000 kilometres, or which the high pressure network (NTS) is 6,400 km.


4 gas interconnectors:

1) Bacton-Zebrugge (Belgium);

2) Moffat and Twynholm (Ireland); and

3) St. Fergus (Norway)


Phase 1 of the Bacton-Zebrugge interconnector compression facilities expansion is under way; completion of the first two compressors due in December 2005.

European Commission's Trans-European Energy Networks Programme includes a plan for a new Netherlands-UK interconnector.

Table 66: Technical information on gas sector - UK

Annexe 9: UK




Gas Act 1986 privatised British Gas and established the regulatory regime. The legal regime has remained, with modest amendments (principally in the Utilities Act 2000) since then. The details of the methodology used to regulate the transportation tariffs has also been affected by two reports by the Monopolies and Mergers Commission in 1993 and 1997.


Office of gas and electricity markets (Ofgem) (since 1998; between 1987 and 1998 - Office of Gas Supply (Ofgas)).

Health and Safety Executive (HSE).

DTI – in the part of setting government’s general policy in energy.


Independent regulatory agency, now headed by a collective board (previously an individual regulator).


Gas Act 1986 established the roles, powers and duties of the regulator and British Gas. These duties were since amended (slightly) in the Utilities Act of 2000. Ofgem is also given powers under the Competition Act of 1998 relating to competition issues arising in the gas sector.

Under the Gas Act 1986 the regulator’s duties were to:

• • • • • •

Secure all reasonable demands for gas - where economic to do so;

Ensure license holders are financially viable;

Secure effective competition;

Protect consumer interests - prices, supply, service (protection of old and disabled);

Promote efficiency and economy amongst licensees; and

Consult with health and safety body.

These duties were replaced in the Utilities Act 2000, which states that Ofgem’s principal objective is to protect the interests of present and future consumers wherever appropriate by promoting effective competition. Subject to the principal objective, Ofgem is required to promote efficiency and economy, protect the public from dangers, and secure long term energy supply. The protection of the consumer interest was therefore set as a primary objective which is constrained by other ‘secondary’ duties.

The duty to protect consumer interests has generally been interpreted as the need to control prices and regulate quality, although the legislation does not explicitly state that this is required. However, a licence condition relating to price controls is included in the Gas Transportation Licence.


Right of appeal to the Competition Commission, formerly the Monopolies and Mergers Commission, was established in the Gas Act (later amended by the Enterprise Act and

Annexe 9: UK


the Utilities Act 2000).

The company can also seek a judicial review of Ofgem’s decisions.


The Competition Commission is an independent public body.

Judicial review is through the courts.


According to the Utilities Act of 2000, in performing its regulatory functions Ofgem must have regard to: a) the interests of special customers including the sick and disabled, the elderly, those on low income and those in rural areas; b) social and environmental guidance issued by the Secretary of State.

In addition, the Health and Safety Executive – an independent governmental agency overseeing safety issues in various industries – controls the safety of Transco’s operations. At the requirement of the HSE, over the next 30 years Transco will undertake a major pipe replacement program (replacing about 92,000 km of its mains network).


None known

Table 67: Regulatory institutions - UK

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When British Gas was privatised a regime of negotiated TPA was in place. Entry failed to emerge under this regime and actions were taken, by the Monopolies and Mergers Commission, Ofgas and the Government to encourage entry and develop a regulated TPA regime.

The 1992 Gas Release programme required non-discriminatory access to be provided. Gas capacity had to be published and transporters were not allowed to buy and sell gas. Entry remained limited under this regime however.

The Gas Act 1995 required the introduction of a network code for access. The network code was implemented in 1995/96, following lengthy negotiations between Transco and the Shippers. This is a legal and contractual arrangement for the supply and transportation of gas in the UK and it governs the gas transmission system. The code defines the rights and responsibilities of all parties (i.e. shippers and NGT). All parties are treated on a non-discriminatory basis under the code. The details in the contract relate to such issues as daily balancing, invoicing, capacity booking and trading, nominations and scheduling, allocation of capacity, measurement of usage, the role of the flexibility market and invoicing.

Retail competition was introduced between 1996 and 1998 and it was over this period that the access regime evolved. There is now a fully developed access code that imposes obligations and responsibilities on parties to an agreement.


Ex ante price control regulation.


5 years.


Already in the 1997 price control, Transco’s transportation and metering activities were each subject to separate RPI-X price controls. Ofgem noted that this form of regulation has proven effective in providing clear targets for companies and has led to significant price reductions for consumers. In the light of these considerations, Ofgem proposed to further separate the different activities that make up Transco’s licensed transportation business. Correspondingly, there are now separate RPI-X controls for the following activities:

• • •

the NTS in its role as transmission asset owner (NTS TO);

gas distribution (LDZ); and

metering and meter reading.


Building block approach – operating expenditure plus depreciation plus return on regulatory asset base


Revenue control - Transco allowed to pass through the costs of prescribed rates and its licence fees.

There is also a system of incentives for Transco to invest in new entry capacity in excess

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of the baseline outputs. Through the retention of some auction revenue Transco is able to earn a higher rate of return for the duration of the price control if it invests to meet demand over and above the agreed baseline entry outputs. If the capacity auctions raise more revenue than would be required to fund the depreciation and financing allowance on further investment then Transco would be able to retain the excess revenue. This would be subject to a cap on returns of between 1.5 and 3 times the cost of capital for the duration of the price control. Transco’s exposure, in the event that it invests above the baseline output measures and market demand for capacity is below that available is limited to a 1 percent reduction in the cost of capital.

There are also incentives for Transco to improve the efficiency of use of the exit capacity.


Yes


An entry-exit charging system is used. The target for the transmission operator is to recover 50% of revenue from exit capacity and 50% from entry capacity. Entry capacity charges are calculated based on the estimated long run marginal cost of developing the system and are determined separately for each exit zone at which a particular offtake point belongs. Charges for entry capacity are determined in capacity auctions.


Next price control review will take place in 2008/09 (in November 2003 Ofgem issued a press statement and an open letter consulting on the possible extension of the gas distribution price controls by one year, suggesting that the controls would be in force from 2002/03 to 2007/08 (inclusive).

Table 68: Regulatory regime - UK

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As part of the building block approach


Market value of assets.

In the 1993 MMC report the opening value was calculated as the book value of existing assets adjusted by a market to asset ratio (MAR) of 60%. The market value and asset value at the time reflected the British Gas company, which included supply and distribution activities.

In the 1997 Ofgas decision on Transco’s tariffs, and the 2001 review, the initial value was adjusted to reflect the assets of the transportation company only. In 1997 the regulator estimated that Transco accounted for 90 percent of the value of the combined business.

To implement separate controls in the 2001 price control review, it was necessary to attribute Transco’s existing RAV between NTS, LDZ, and metering activities. Transco initially proposed separating those activities according to the relative book value of the assets, but with a transfer from metering to transportation to reflect the recovery of certain stranded metering costs. However, the draft proposals adopted an unfocused approach, consistent with the method for valuing Transco’s overall RAV. This approach was retained after consultations in the final price control proposals.


At the 1993 review, and Competition Commission inquiry, the company was allowed to recover depreciation on a CCA basis on pre-Dec. 1990 assets plus a MAR abated return on current cost value of pre-Dec.1990 assets plus a depreciation and full return on investment since 1990. Ofgas, and subsequently the MMC in 1997 argued that this would over-recover the cost of the assets that were bought by investors – although investors were only allowed a return on the market value of the assets (which was less than the current cost value) they were allowed to recover the whole current cost depreciation. Over the life of the assets, the company would therefore recover the current cost value, but shareholders had paid less than that for the assets. Consequently, there was a distributional concern. The remedy was that the company could only recover depreciation on the regulatory value of the assets, defined as the market value in Dec 1990.

In the 2001 price control, Ofgem described issues surrounding the valuation of Transco’s assets at 31 December 1991, and two different approaches that could be used to arrive at a value for these assets, the focused or unfocused approaches. In deciding between the two, a range of factors were considered including market evidence and 1991 asset values, regulatory consistency, the views of interested parties, and the views of the MMC. The draft proposals also noted that as time progresses the RAV will increasingly reflect the value of new investment undertaken since December 1991 and that a change to the initial RAV would create uncertainty and may increase Transco’s cost of capital. In light of these considerations, the draft proposals contained an unfocused valuation for Transco’s initial RAV, consistent with the MMC’s 1997 report. After the consultations, this approach was retained in the final price control proposals.


31/12/1991

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CCA value adjusted by the MAR


In its 1993 report the MMC distinguished between assets in existence on 31 December 1991 which were included in the initial value and investments made after that time that were rolled forward in the RAB. The same approach was used by Ofgas in its initial and final proposals in 1996, by the MMC in its 1997 report and by Ofgem in its 2001 decision.


Assets were revalued by the MAR.


Separate depreciation rules were used for new investments and for existing (pre-1992) assets. See discussion on depreciation below.


Ensure return earned by shareholders reflects the investment made by them.


Current cost asset values were taken from the accounts at the time and adjusted by the MAR. The valuation has since been adjusted in the 1997 and 2001 regulatory reviews to ensure that the scope of the price control (transportation charges only) was reflected in the asset valuation and the initial value was inflated by RPI.


In the 1997 price control a MAR-adjusted deprecation rate was applied for pre-1992 assets and a straight-line rule was used for all other assets.

The 2001 price control proposals described the approach that existed then as relatively complex, difficult to monitor and relying on Transco providing detailed information on additions and disposals across a relatively large range of asset categories. To address these concerns, it was suggested to simplify the approach to calculating depreciation post-April-2002. The resulting approach assumes that the assets existing at April 2002 have been accumulated evenly over time. A straight-line depreciation charge is calculated for each group of assets separately in each year.


In the 2001 price review (for the period 2002 to 2007) Ofgem made the following assumptions about NGT’s transportation assets:

• •

existing assets - 28 years

new investments - 45 years

In the 1997 price control the MMC, and Ofgem, made the following assumption about the NTS assets:

Pipelines - 48 years Above ground installations - 24 years Compressors - 35 years Terminals - 30 years Services - 35 years Meters - 20 years Plant and machinery - 20 years Storage facilities - 40 years Telecommunications - 10 years

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Vehicles - 6 years Other - 5 years


The opening value is rolled forward from 1991 using actual and projected information on investment, movements in replacement value and depreciation for each year (MAR-adjusted for pre-1992 assets). Adjustments are also made for movements in working capital and customer contributions since the opening calculation.

As well as providing a return on the unamortized balance of Transco’s December 1991 assets, the 2001 Transco price control was designed to allow for the financing of efficiently incurred network capital expenditure made after December 31, 1991. There is no market-to-asset ratio adjustment to this investment, so Transco is able to earn a full return on allowed capital expenditure.

The RPI is used as the inflation index for rolling the initial value forward. This is also consistent with the use of the RPI in the price formula. The use of the RPI to restate RAB in current prices was adopted by the MMC in the 1997 price control (but not before). The alternative index, favoured by the MMC in its earlier report on BG and by Ofgas in its earlier years, is a current cost (CC) index, which attempts to capture changes in the current cost of replacing the services embodied in the specific assets underlying the RAB. This description shows the inappropriateness of a CC index if we believe that the RAB represents a capital fund of shareholders’ investment in the firm (which is implied by the MAR adjustment) rather than the specific investments made with those funds by the firm. The effect of using the CC indexes is to tie investors’ returns to the replacement prices of firm-specific assets. As a consequence of this, real holding gains (those representing specific price rises in excess of the RPI) and real holding losses (such as are often caused by technical progress) will disadvantage shareholders. Such a system penalises technical progress. It can also lead to extensive regulatory uncertainty and possibly to dispute over the identification of the appropriate specific index or asset price, which was why, for example, OFWAT (UK water regulator) decided at an early stage to use general rather than specific indexes for the restatement of RAB.

The value of the RAB for the current control period is shown in Table 70.


None known

Table 69: Methodology used to calculate the RAB - UK

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£bn (2000 prices)

2002/03 2003/04 2004/05 2005/06 2006/07

Opening asset value

12.7 12.8 13.0 13.0 13.0

Depreciation 0.5 0.6 0.6 0.6 0.6

Capital expenditure

0.7 0.7 0.6 0.5 0.5

Closing asset value

12.8 13.0 13.0 13.0 12.9

Table 70: Transco's asset value (2002 price control)

Source: Ofgem (2001), Review of Transco's price control from 2002 - Final Proposals


Capital expenditure is investment in assets whose benefits can be expected to last for some years, such as high-pressure pipelines and lower pressure mains. For pipelines and mains Transco makes a further distinction between capital and replacement expenditure.


Yes. Only 50% of replacement expenditure added to RAB (the other 50% to operating expenditure).

This is a novel treatment of the replacement expenditure by the regulator, adopted due to the massive scale of the expected replacement programme. In part this results from a decision of the HSE (Health and Safety Executive) to replace all cast and ductile iron mains within 30 meters of premises over a 30 year period. During the present price control period Transco is expected to spend about £1.3 billion.

As replacement expenditure is projected to increase significantly, a key issue becomes the method of financing this enhanced level. The renewal programme is primarily concerned with present safety requirements rather than increasing the network’s capacity or functionality for the benefit of future consumers, suggesting these costs should be expensed and met within the price control period. Nevertheless there will be some advantages to consumers in the future as replacement spending will be lower and newer assets tend to require less repair and maintenance.

To deal with these tensions, to ensure that Transco is able to finance its activities and to ensure that price reductions are sustainable beyond the next price control period, Ofgem has decided that 50 percent of replacement spending over the next price control period will be expensed in the year that it is incurred, and 50 percent will be treated as capital and added to the regulatory asset base.

Prior to the current price control, all replacement expenditure was treated as capital expenditure.

In the current price control, there is also an additional incentive system, under which

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Transco is allowed to keep some of the savings if it completes replacement program more efficiently than was forecast at the time of the price control, and shares in the additional costs should the actual replacement cost more than was forecast.


None, but may become an issue at the next price control review with respect to capital overspend.

Currently, no capital overspend is included in RAB, and in practice Transco was consistently “beating” the allowed capital expenditure level. But because Transco is expected to have a very large capital overspend by the next price control review, Ofgem has issued an open letter suggesting that any overspent capital will be classified into one of the three categories, or “pots”:

• • •

inefficient

necessary and efficient, but not bringing any immediate benefit to the customers

necessary, efficient and bringing immediate benefit to the customers.

Capital overspend in the third category will be allowed for full immediate recovery (as if it was in RAB from the beginning); the second category will be allowed for recovery with a lag (at the next price control period); and the first category will not be allowed for recovery.

So far there have been no clarifications from Ofgem regarding practical rules for classifying capital overspend into these three pots.


Ofgem indicated that there will be such test (see the previous section), but has not announced any specific methodology yet.


Until now, the incentive was to beat the capital expenditure that had been allowed

This may change depending on the treatment of capital overspend at the next review


Not discussed as an issue by Ofgem – assume assets are included.


See above

Table 71: Treatment of capital expenditure in the RAB - UK

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CAPM, plus in some cases the regulator notes that Dividend Growth Model produced similar results – although detailed discussion of the calculation is provided only for CAPM.


The risk free rate

A value of 2.75% was used for the risk free rate. This was based on:

• •

estimates made previously for other industries (water or electricity); and

current and projected yields on “quasi-risk-free” financial instruments of different durations – index linked gilts and conventional bonds.

In conducting these estimates, Ofgem looks at the arguments given by the company (Transco), and, more generally, tries to take into account all available information about the future behaviour of the financial markets (such as, for example, impact of future adoption or abolition of laws and regulations).

The beta

An equity beta of one was used.

Transco’s regulated gas transportation business is not a stand-alone publicly quoted company, which makes it more difficult to calculate its beta (no data on the regulated company’s stock valuation over time). Ofgem uses submissions of its consultants, as well as those of Transco/Transco’s consultants, to arrive at some value of beta which it believes is plausible.

Equity risk premium

A value of 3.5% was used for the equity risk premium.

Historical levels of equity risk premium used only to a limited extent (because past trends are usually regarded as too high). Instead, Ofgem relies on evidence from surveys of institutional and investor opinion, as well as on estimates made recently in other regulated industries.


As a sum of the risk-free rate and debt risk premium.

Risk free rate is calculated as described above.

A value of 1.5% to 1.9% was used for the debt risk premium. This was calculated as the spread between the yields on corporate bonds and those on gilts of comparable maturity. In doing so, assumption is made of whether the regulated company (Transco) will maintain its current investment rating, or how it will change.


A gearing of 62.5% was assumed. This is the value that was determined as the efficient range of gearing for the National Grid Company (NGC) in the electricity transmission price control review (took place before the gas price control review).

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“Cost of equity” component of WACC is adjusted as follows:

In its report on Cellnet and Vodafone, the MMC adjusted the cost of equity finance upwards by a tax wedge to take account of corporate tax payments. In calculating the tax wedge, the assumption was that the companies would pay the mainstream rate of corporation tax of 30 per cent, giving a multiplier of 1/(1-0.3), or 1.429.

Ofgem adopted this same approach in its review of the electricity transmission and distribution businesses, and did the same in the gas review.


Yes – other regulated industries (water, electricity, telecoms)


Pre-tax WACC: a “low-high” range of 6.0%-6.25%, with the “high” value (6.25%) used in the final proposals. Post-tax rate not calculated explicitly (post-tax cost of equity 6.25%, gearing 62.5%, cost of debt (low-high) 4.25%-4.65%).


None known

Table 72: Determination of the WACC – UK

INFORMATION SOURCES


• www.transco.uk.com

•

•

Transco (2004), Gas Transportation Charges Effective from 1 October 2004, September


http://www.ofgem.gov.uk

• • •

•

Ofgem (2003), Separation of Transco’s distribution price control – Final Proposals, June

Ofgem (2001), Review of Transco’s Price Control from 2002. Final Proposals, September

Monopolies and Mergers Commission (1997), BG Plc A Report under the Gas Act 1986 on the restriction of prices for gas transportation and storage services, May

Monopolies and Mergers Commission (1993), British Gas plc: Volume 1 of reports under the Gas Act 1986 on the conveyance and storage of gas and the fixing of tariffs for the supply of gas by British Gas plc, August

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http://www.transco.uk.com/

http://www.ofgem.gov.uk/


Legislation

• • • •

•

Gas Act 1986

Gas Act 1995

Competition Act 1998

Utilities Act 2000

Other


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