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Discussion Paper

Matteo Urbani

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Executive Summary

Traditionally in Europe, before the liberalization of electricity markets, cross-border

interconnections were built for reinforcing national security of supply and were financed by

the national tariff mechanism. Today, interconnections have acquired a Community

dimension, as they are fundamental to the setting of the Internal Electricity Market (IEM) and

to promote the deployment of renewable energy sources. In this respect, they have both a

national and a community-wide relevance.

However, even though interconnections contribute to the social welfare regionally, their

investment costs still remain borne solely by a national level, and there is not yet a European

regulation addressing the issue of community-wide benefits to be covered by a common

incentive mechanism. TSOs investment decisions are fundamentally driven by their national

mission, which is mainly to guarantee the security of supply. This mission incurs investment

costs (fix costs) as well as operation and maintenance costs (variable costs). Both types of

costs are generally covered by a use-of-system tariff, generally calculated according to cost-

plus and/or (RPI-X) mechanisms. Such a tariff is designed and periodically revised to provide

TSOs with sufficient financial resources to invest in new transmission infrastructures as

needed, and to remunerate assets’ owners or shareholders.

At present, the achievement of the IEM cannot be realized without a strong development of

interconnections. The traditional methodology for evaluating investments benefits and for

covering their cost is not incentivizing enough to enable the construction of the required

cross-border infrastructures. The current arrangement, combining a national tariff

mechanism and a community-wide ITC mechanism (covering variable costs incurred by

parallel flows in interconnected grids caused by energy trading between markets), is not

found satisfactory by European stakeholders.

To start the process for setting a Community-wide regulation able to promote cross-border

investments, the Realisegrid project has recommended the establishment of a costs-

benefits analysis which would contribute to distinguish benefits and costs between national

and community levels. This approach, integrated in the ENTSO-E TYNDP-2012 methodology,

could be also adopted for evaluating interconnection projects in the Mediterranean area.

Furthermore, the Regulation No. 347/2013/EC lastly came into force, is expected to

contribute to reduce risks and accelerate network development of the so-called projects of

common interest (PCIs), which include also cross-border infrastructures between Member

States and third countries. This action represents a useful and beneficial tool that may help

to foster interconnection investments also across the Mediterranean.

However, according to ENTSO-E, to convince investors to finance complex projects it does

not suffice to only reduce risks when projects are labeled as priorities, but in this respect

providing adequate remuneration, in terms of a common overarching incentive at European

level, is a prerequisite as well. Regarding that, ENTSO-E believes that a priority premium

mechanism is an efficient and effective solution to differentiate returns and foster the

required investments in a timely manner.

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Table of Contents

Executive Summary ........................................................................................................ 2

Introduction ..................................................................................................................... 4

1. The reform process .................................................................................................... 6

Box 1. Cross-subsidization externalities ................................................................ 9

Box 2. Unbundling options .................................................................................... 10

2. Interconnection investments and incentive regulation: the current debate ........... 13

3. New guidelines for European and trans-European interconnections investments 19

Box 3. TSOs and financial issues .......................................................................... 28

Box 4. The Italian Experience ................................................................................ 32

Conclusion .................................................................................................................... 33

References .................................................................................................................... 35

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Introduction

Before the beginning of the liberalization process of the electricity sectors in the EU,

interconnections represented only a physical instrument for guaranteeing security of

supply and solidarity among countries in case of contingencies. Today, investing in

interconnections1 constitutes the core of the Internal Electricity Market (IEM)

implementation, a key factor for the integration of variable energy into the grid, and

the foundation of a successful Euro-Mediterranean energy cooperation.

In general terms, a more interconnected electricity system contributes to foster

competition by reducing congestion2, and is expected to favor market access, as well

as facilitate the deployment of renewables, with benefits for the social welfare.

As for the European experience, to fulfill the objectives of security of energy supply,

market integration and energy solidarity, in a sustainable way, the Treaty on the

Functioning of the European Union (TFEU – Consolidated Version)3 stresses the need

to: “ensure the functioning of the energy market; ensure security of energy supply in

the Union; promote energy efficiency and energy saving and the development of new

and renewable forms of energy; and promote the interconnection of energy

networks”.

Furthermore, more recently, the communication from the Commission of 7

September 2011 entitled “The EU Energy Policy: Engaging with Partners beyond Our

Borders” underlined the need for the Union to include the promotion of energy

infrastructure development in its external relations with a view to supporting socio-

economic development beyond the Union borders. The Union should facilitate

infrastructure projects linking the Union’s energy networks with third-country

networks, in particular with neighboring countries and with countries with which the

Union has established specific energy cooperation.

A stronger interconnectivity between energy networks constitutes then a key aspect

duly underlined in the Treaty and in this respect, cross-border transmission

investments can benefit all three pillars of the European energy policy: security,

affordability (i.e. competitiveness), and sustainability of energy supply.

Regarding security of supply, interconnections allow for improving solidarity between

Member States in case of disruption with benefits in terms of social welfare as the

cross-border prices convergence and the reduction of congestions, a more efficient

system operation and the reduction of unserved energy.

1 Interconnection refers to “a transmission line which crosses or spans a border between Member States and

which connects the national transmission systems of the Member States” (Regulation (EC) No. 714/2009 of the

European Parliament and of the Council of 13 July 2009 on conditions for access to the network for cross-border

exchanges in electricity, OJ L 211/15, 14.8.2009). 2 Congestion is understood as “a situation in which an interconnection linking national transmission systems

cannot accommodate all physical flows resulting from international trade requested by market participants,

because of a lack of capacity of the interconnectors and/or the transmission systems concerned” (ibid.). 3 Article 194 (Title XXI), Official Journal of the European Union – C 115/47 (9.5.2008).

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Respect to competitiveness, investing in interconnections helps to mitigate market

power of incumbents, which are driven to shrink their prices to cope with lower-cost

imports, exhorting in the meanwhile to reduce managerial slack and X-inefficiencies

due to competitive pressure.

Finally, with regards to the sustainability of supply, interconnections are supposed to

facilitate renewables integration into the grid by improving transmission flexibility,

which is an essential condition to manage variable generation, and allowing for a

more efficient exploitation of the regional generation mix. Indeed, when grids

become highly loaded, the tolerance to such variations decreases, and coping with

this effect requires huge investments to improve system reliability, as well as the

increase of interconnection capacity to adjacent power systems. With the growing

penetration of variable generation the need for reserves becomes critical, and the

possibility to share generation on a regional basis represents an important solution

for rationalizing and reducing the overall need. In this regard, interconnections can

play an important role in distributing power generation across Europe (and in the

long run also across Mediterranean), thus flattening out peak renewable production

with benefits in terms of price volatility attenuation.

However, in order to achieve the liberalization targets (i.e. reducing electricity costs

and improving customer services quality by promoting market access for new

operators and, hence, shrinking the market power of historical monopolies), the

progressive opening of the European electricity sectors entailed the redefinition of

several parameters pertaining to incentive regulation, regulatory governance, and

market design assessment, which affected transmission investments, and

particularly cross-border ones.

The investment needs up to 2020 in electricity transmission infrastructures of

European relevance have increase significantly. This escalation compared to past

trends and the urgency of implementing the electricity infrastructure priorities

requires a new approach in the way transmission infrastructures, and in particular

those of a cross-border nature, are regulated and financed.

The Commission Staff Working Paper for the Council of 10 June 2011 entitled

“Energy infrastructure investment needs and financing requirements” stressed that

approximately half of the total investments needed for the decade up to 2020 are at

risk of not being delivered at all or not in time due to obstacles related to the

granting of permits, regulatory issues and financing.

Today the debate is open. The present discussion paper has the objective to

investigate the different stances on the regulatory issues, in order to identify the best

solutions able to provide right incentives to the investors, which are confronted with

long-term uncertainty and intricate administrative procedures, typical of cross-

border network investments.

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The paper is structured as follows: firstly, the European electricity market reform

process is presented through a synthetic overview of the most important and recent

developments; then, the current regulatory debate regarding interconnection

investments is illustrated underlining challenges, drivers and drawbacks, and

describing the main options existing at the present as well as some alternative

schemes recently tested; finally, the new assessment methodology adopted by

ENTSO-E for interconnections investments within EU (and potentially applicable to

the Mediterranean cross-border projects) is described and discussed - also in light of

the last regulatory measures lately adopted - to enrich the debate.

1. The reform process

Although at the beginning the development of electric generation was sustained by

several small companies, as the industry grew, the entire chain has been vertically

integrated into monopolistic entities, either state-owned (in most cases) or privately-

owned. Various factors favored this evolution: the need to develop transmission

networks; the difficulty (in the first half of the 20th century) to effectively manage third

party access and real time demand-supply; the sheer size of the capital intensive

nature of the electricity sector.

In Europe, after the Second World War, the need to support a fast growing electricity

demand, in turn boosted by the post-war reconstruction effort, the scarcity of fuel,

and the lack of infrastructures, led to a wave of nationalizations resulting in the

creation of industry giants such as Central Electricity Generating Board (UK),

Electricité de France (FR), and Enel (IT). This approach was also based on some

objective challenge representing a highly capital-intensive effort with long payback

periods (but significant society-wide benefits) as the need of building a capillary

system able to ensure an equal access to electricity for all citizens.

In the last two-three decades, and in economies with relatively large and mature

electricity supply industries, this view came under heavy criticism, as a consequence

of:

- The new neo-classical economic theory in the early 1980s, which insisted that

free and competitive markets were more efficient at delivering basic services,

and that divestiture of state-owned assets would have flow-on social benefits

in terms of improved resource allocation, innovation, and ultimately greater

employment opportunities;

- Technological advances that allowed for the development of smaller-scale

generation plants closer to demand centers, in sizes potentially interesting for

large consumer industries (especially the Combined Cycle Gas Turbine

technology), with higher efficiency compared to the conventional steam units

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that formed the backbone of the utilities’ generation fleets and which was

relatively easier to master than conventional coal fired boilers, large hydro

plants or – even more – nuclear power plants;

- Declining fuel prices, especially true for the oil-linked gas price in the mid-

nineties.

In particular, the advances in information technology made possible the management

of a plurality of producers sharing one common transmission infrastructure in a

ensured way, supporting also the creation of an electricity market operated largely

through electronic means (with buying and selling designed to match demand on a

five minute basis throughout the day and night). Besides, the ability of market players

to have access to real time information on all aspects of their operations, and on

constantly changing market prices for electricity, showed as a disaggregated

industry structure with high levels of economic efficiency became feasible.

Therefore, in the 1980s, with the support of the economic theory that deeply

contributes to the evolution of the network utilities regulation, and particularly of the

industrial organization of the electricity sector4, some fundamental remarks have

been addressed to the traditional monopolistic structure and several criticisms have

been raised against the vertically integrated scheme5.

On the one hand, the bureaucratic bottlenecks (e.g. organizational slack), the

tendency of overinvesting (i.e. Averch-Johnson effect)6, and the asymmetry of

information between the regulated monopoly and the regulator7 involved negative

externalities no longer tolerable8.

On the other hand, the technological progress, as well as the “maturity” of the grid,

drove to a rethinking of the vertically integrated industrial structure, by opening up to

competition the upstream (power generation) and the downstream segments

(electricity wholesale trade and retail sale to final consumers) of the value chain,

keeping the transmission and distribution network as regulated natural monopoly9.

4 Cf. Baumol, Panzar and Willig (1982 and 1988); Sharkey (1982); Weitzman (1983).

5 However, it is important to keep in mind that the electricity supply industry has important physical

characteristics as (i) significant sunk costs which limit new entries in the market, (ii) vertical stages of production

with different optimal scales, and (iii) a non-storable good delivered via a network which requires instantaneous

physical balance of supply and demand at all nodes, which would continue to influence the definition of its

regulatory design (cf. Jamasb and Pollitt, 2005). 6 Cf. Averch H. and Johnson L., (1962), Behavior of the Firm under Regulatory Constraints, American Economic

Review, No. 52, 1962, p. 1052-1069. 7 Cf. Laffont J-J. and Tirole J., (1993), A theory of Incentives in Procurement and Regulation, MIT Press, 1993.

8 Regarding that, the daily operation in the industrial field of reference and the direct contact with consumers,

provide to the regulated monopolistic firm a level of information significantly superior than the regulator about

the demand for regulated services the firm supplies, the minimum possible current cost of services delivering,

and the potential for less costly future provision. Overseeing and directing the activities of a monopoly supplier

can become nearly impossible for a regulator when the information and expertise are severely limited, and the

lack of physical and financial resources prevent to overcome these limitations (Armstrong and Sappington, 2006) 9 In this regard, works on overcapitalization of the monopolistic firms opened the way for a more general

reflection on their efficiency in a non competitive environment, where the lack of competitive pressure represents

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The reforms generally apply to a mature system, which means that most of the

production, transmission and distribution infrastructures are already completed, and

that markets are solvable. In fact, in non mature phases, integrated monopolies may

be preferred to facilitate investments also by reducing transaction costs10, but once

the infrastructure is completed, the main objective is to improve efficiency and to

reduce price for the final consumer, which should justify privatization and

liberalization.

This process of regulatory reforms and competitive markets development implies the

adoption of several measures which represent the cornerstones of the sector

liberalization, and that are considered as key components of the new market design,

entailing a radical change of the electricity industrial organization, with significant

effects on investments planning.

Two measures have to be outlined primarily: the unbundling of the vertically

integrated incumbents, which open a part of the value chain to the competition

(upstream and downstream) keeping the network’s activity regulated; and the

establishment of independent national regulatory authorities (NRAs).

The unbundling regime

The vertical separation (unbundling) of potentially competitive segments (e.g.

generation and retail supply) from segments that will continue to be regulated

(distribution, transmission and system operations) is one of the main ex ante

regulatory measures allowing for a market opening. This operation of “industrial

decoupling” is considered essential for guaranteeing the existence and the

functioning of a competitive market, by avoiding cross-subsidization and

discriminatory policies affecting the access to distribution and transmission

networks, upon which all competitive suppliers depend.

A fair unbundling represents the goal and the core of liberalization reforms, and it is

fundamental to improve markets transparency as well as to promote the cost-based

pricing development, considered more efficient than the previous tariffs based on

cross-subsidies. Furthermore, as the European Commission stressed, a vertically

integrated company has “no incentive to develop the network in the overall interest of

the market with the consequence of facilitating new entry at generation or supply

levels”11. This is particularly true for interconnections that generally are expected to

increase competition in the incumbent’s home market.

a negative incentive for the firm to be efficient (cf. X-inefficiency, Leibenstein, 1966). Leibenstein H., (1966),

Allocative Efficiency and X-Efficiency, American Economic Review, Vol. 56, p. 392-415. 10

Cf. Coase R. (1937), The Nature of the Firm, Economica, p. 386-405 and Coase R. (1988), The Firm, the Market and the Law, Chicago University Press; Williamson O. (1989), Transaction Costs Economics, in Handbook of

Industrial Organization, Schmalensee & Willig (eds.), North Holland. 11

European Commission, DG Energy and Transport (2007c): “Impact assessment accompanying the legislative

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Box 1. Cross-subsidization externalities

In economic terms, cross-subsidy is a kind of improper assignment of costs among

different activities that may also be easily utilized by a vertically integrated incumbent to

place potential entrants at a competitive disadvantage. In practical terms, for a

vertically-integrated company it is only an internal transfer of costs from one activity to

another, by enabling the integrated company to use profits from its monopoly operation

to cover the costs of competitive operation.

However, from the perspective of its potential competitors, this type of cost-accounting

system provides a vertically-integrated company with an opportunity not only to

overcharge their potential competitors for use of its network, but also to unfairly lower

prices on the sale of electricity in the competitive (generating or supply) markets.

As a result, a vertically-integrated company can effectively, and at the cost of potential

competitors, maintains its market share and block development of competition in a

formally open market.

One organizational form to guarantee the achievement of this market design implies

the designation of a single independent transmission system operator (TSO),

essential to fairly manage the network operations by ensuring a transparent and fair

third party access (TPA), as well as a transparent generation schedule for meeting

demand and so guiding the investments in transmission infrastructure to meet

reliability and economic standards. This first step aims at promoting the wholesale

market, breaking up the exclusive right of supply for the owner of the net12.

The transmission network could be in the regime of public ownership (state or

municipal), or private-owned. The unbundling can be fully structural - implying the

ownership separation from the generation and retail segment of the historical

monopolistic incumbent - or alternatively, only functional with no need of proceeding

to the ownership transfer, as recently admitted by the European regulation: the

operator of transmission system is not the owner, and is fully independent in order to

prevent the possibility that shareholders of the vertically integrated group govern the

infrastructure.

package on the internal market for electricity and gas”, Brussels, 106 pp. 12

The introduction of the Directive 90/547/EEC introduced the possibility of free transit between producers and

wholesale traders of electric energy.

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Box 2. Unbundling options

The EU, aiming to create a single market in electricity and gas, made unbundling a

policy goal. The EU distinguishes different types of such unbundling. The main types

are:

- Accounting unbundling: the least drastic form of unbundling; separate accounts

must be kept for the network activities and generation activities to prevent cross

subsidization;

- Functional unbundling (also called management unbundling): this form

requires, in addition to keeping separate accounts, that the operational activities

and management are separated for transmission and generation activities;

- Legal unbundling: this form requires that transmission and generation be put in

separate legal entities;

- Ownership unbundling: the most drastic form of unbundling. Generation and

transmission have to be owned by independent entities. These entities are not

allowed to hold shares in both activities.

In 2009, as part of the Third Energy, new electricity Directive 2009/72/EC were issued.

As regards transmission, legal unbundling was considered ineffective. Therefore,

ownership unbundling was set as the minimal level of unbundling. The new Directive,

however, still allow the less rigorous level of legal unbundling, if the transmission

network is run by an independent system operator. This still allows for an effect of

vertical integration on competition and interconnector investment incentives.

The regulatory authority

Directly related to the creation of an independent TSO, the national regulatory

authorities (NRAs) play a crucial role in establishing and developing a competitive

electricity market. There are several normative arguments for justifying the creation

of such authorities. A classic economic justification for regulatory intervention in the

liberalized power market is market failure, e.g. the existence of natural monopolies.

In electricity, transmission and distribution networks remaining natural monopolies,

regulators must guarantee a transparent and fair access to these networks for all

competitors, as well as oversee that monopolistic resources are spent efficiently.

The NRAs act both through ex ante measures, aimed at opening the market as well

as at ensuring the existence of a competitive and transparent environment; and

through ex post measures (often coupled with the action of antitrust agencies) aimed

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at guaranteeing that competitive markets exist in practice and that operate

correctly13.

In order to ensure a real independence, especially where state-owned monopolies

have historically prevailed, the liberalization necessitates a clear separation of the

state as owner and potential seller of public utilities, and the state as regulator,

either through privatization of public assets or through the establishment of

independent regulators, or both. In most of the cases the option privileged has been

the establishment of sector specific independent regulators, combining the

independence from commercial interests with separation from the ministerial

administration. The aim is to reduce both the risks of “regulatory capture” and

asymmetric information that only a real independence can guarantee14, even though

often is not fully satisfactory to ensure a transparent and non-discriminatory market

functioning15.

***

In EU, despite the European Commission promotes a common regulatory framework,

there are still very different approaches about the implementation of competitive

electricity markets due in particular to the different legal and administrative tradition

of Member States.

At the present the European electricity liberalization process is progressing at a

steady pace and the new market design described in the Third Energy Package is

taking place, radically changing the regional industry landscape. Nevertheless, some

deficiencies in terms of market integration and regulatory harmonization are still

unresolved, affecting transmission investments with consequences on social welfare.

The restructuring of the electricity sector organization, by imposing the unbundling

of the national monopolies vertically integrated, changed the frame of reference of

the system adequacy, and modified radically the generation and transmission

investment planning. Today this exercise is more complex. Different actors and a

series of decentralized decisions - partially based on prices - revolutionized a task

13

Cf. Frison-Roche M.-A., (2006), Le couple ex ante – ex post, justificatif d’un droit spécifique et propre de la régulation, In: M.-A. Frison-Roche (ed), Droit et Economie de la Régulation, vol.4, Les engagements dans les

systèmes de régulation. Paris: Presses de Sciences-Po & Dalloz, p. 33-48. 14

“The regulatory authority should be a distinct administrative institution from the executive branch, and independent or interdependent from the executive branch in its procedures and decision-making process. An element of independence refers to commissioners, members, and heads of the regulatory authority being appointed by transparent methods for fixed mandates.” (World Forum on Energy Regulation, 2003). 15

Cf. Stigler G. and Friedland C., (1966), What can Regulators Regulate? The Case of Electricity, Journal of Law

and Economics, No. 4, 1966, p. 1-16; Stigler G., (1971), The Theory of Economics Regulation, Bell Journal of

Economic and Management Science, No. 2(1), 1971, p. 3-21. In this regard, the development of incentive

regulatory methods has been historically promoted with the aim to reduce the vulnerability of the regulator vis-à-

vis the risk of manipulation by regulated firms, in a situation of asymmetric information and lack of independence

(Cf. Joskow P. (2005), Incentive Regulation in Theory and Practice: Electricity Distribution and Transmission Networks, Working Papers 05-014, MIT, Cambridge, MA). Indeed, independent regulatory authorities must hold

exclusive decision-making powers both in rule making and rule application, as well as, in certain cases, litigation.

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that until recently was conducted by the historical monopolies, without any concerns

about the externalities due to the asymmetry of information between generation and

transmission segments.

This implied that also the investments in interconnections have slowed down

hampering the European electricity integration, which is suffering of a lack of

incentives to invest in additional cross-border transmission capacity. In this regard,

reforms of regulated TSOs have become more and more necessary, as the Third

Energy Package (Directive 2009/72/EC; Regulation No. 714/2009) clearly points out.

Within such a new context, TSOs have emerged as new companies in a regulated

environment where networks are considered essential facilities16. Some TSOs have

been privatized and their stock company status, yet having to operate in a regulated

regime fixed by regulators upon the hypothesis of natural monopoly, allows them to

make profits. Additionally, their planning activities have become more difficult

because of the complexity of foreseeing trans-national transits, also due to variable

generation sources and uncertainties tied to the bidding behavior of the several

independent market players.

Regarding that, the urgent need to develop cross-border infrastructure impose an in-

depth investigation of the most efficient remuneration policy, within a common

regulatory framework, and with particular attention to the incentives schemes. This

investigation involves various stakeholders such as Transmissions System Operators

(TSOs), national regulators and regional institutions. The aim is to harmonize

national needs and pan-European interests, in order to find the best way to

guarantee a better social welfare in the long-run, with benefits also for the SEMCs

(South and Eastern Mediterranean Countries), within a broader Euro-Mediterranean

regional development.

In this respect, common rules and harmonized procedures become essential to

foster investments and promote a more beneficial power trade. This is true not only

in EU but also in the South Mediterranean, where the cross-border integration of

electricity systems is still weak and interconnections needs are far from being

satisfied.

16

Cf. Posner R.A., (1969), Natural Monopoly and Regulation, « Stanford Law Review », vol. 21, 548-643;

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2. Interconnection investments and incentive regulation: the current

debate

Different regulatory approaches for transmission investments are used worldwide,

ranging from the traditional cost-plus model to the more performance-based “cap-

regulation”. In EU, regulated schemes are the rule and they can be only exceptionally

derogated by adopting the “merchant” option, an alternative scheme based on a

private investment approach where parties are fully or partially exempted from the

rules on third party access, and/or the rules on the use of congestion rents.

Regulated schemes

The cost-plus approach, historically applied in most European countries, is the

traditional scheme. The TSO is in charge of the grid expansion plan by setting the

investment needs which are then submitted for the approval of the regulator which

sets tariffs to allow the network operators covering both their capital and operating

expenditures. Within this approach, the financial risk for the investor is very limited,

since it is remunerated by a fair regulated rate-of-return.

There are two possible ways to establish a cost-plus mechanism: i) certifying

standard costs (investment, operation and maintenance costs); ii) launching a public

tender for the realization of the network expansion. In the latter, the regulator may

ask each potential builder to propose a tariff for the lifespan of the project, awarding

the project to the company that bids the lowest tariff. The tendering is the option that

better contributes in reducing the potential risk of overinvestment and

overcapitalization (i.e. Averch and Johnson effect, 1962)17.

An alternative scheme usually followed is the so-called “cap-regulation”. The

regulator would not retain an explicit role in approving or opposing any specific

infrastructure project, but simply participate in assessing TSO’s “baseline

investment” forecasts of expected demand and supply. The asset remuneration is

then based on some form of performance measure. The regulator fixes ex-ante a

price (or revenue) cap that represents the reference for the TSOs investment

strategies within a given period.

In result, the TSO takes on the risk of failure and the global reward is generally

subject to RPI-X procedures18, which are applied for a fixed control period. In this

case, market signals play an important role to point out new investment needs.

17

This effect, empirically proven by Stigler and Friedland (1962) and Courville (1974), occurs because of the

relative favorable risk investment position that is guaranteed to the monopolistic networks operators. 18

It is the rate of inflation, measured by the Retail Prices Index (RPI) and subtracting expected efficiency savings

X. The system is intended to provide incentives for efficiency savings, as any savings above the predicted rate X

can be passed on to shareholders, at least until the price caps are next reviewed (usually every five years). A key

part of the system is that the rate X is based not only on a firm's past performance, but on the performance of

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Depending on the kind of regulatory mechanism, the incentive framework to promote

network investments will differ accordingly. The first approach (i.e. cost-plus model)

could be advantageous when the investments are particularly onerous and/or in the

event of great economic uncertainties. The incentive to invest can be triggered by

high levels of remuneration certainty, which constitute the major issue for network

operators, but there are no real incentives to efficiently reduce costs. In this case,

there exist two main risks in terms of overcapitalization and technical inefficiency

(i.e. x-inefficiency, Leibenstein, 1966), without forgetting that inflation could worsen

the situation.

The second mechanism (i.e. cap schemes) certainly encourage cost cutting, which

may promote efficiency, but at the risk of not stimulating adequately such a long-

term investment, as cross-border ones are, generally submitted to intricate and

costly permitting procedures (mainly related to the satisfaction of the social

acceptability) within different national legislations.

Under both mechanisms the economic incentive for the TSO to invest in a network

facility may be deficient if the rate of return is too low or the performance index used

for setting remuneration parameters does not reflect real costs. Furthermore, the

cross-border typology of investments often entails obstacles, particularly due to the

lack of regulatory harmonization between countries. Thus, in order to set an

appropriate framework for the stimulus of these investments, first of all it is

important that incentive mechanisms encourage coordination among TSOs. This may

be achieved through the harmonization of performance indicators and by taking into

account that the expected benefits for the consumers should be accounted for. As a

general rule, when regulatory differences exist, implying a lack of shared rules, trade

opportunities drop (Olmos and Pérez-Arriaga, 2009).

Different typologies of investments, depending on their short or long-term nature,

may be affected differently by regulation and in particular by incentive regulation.

Theoretically, the incentive mechanism should cover as much as possible all costs

incurred by the network operator (i.e., operating costs, capital costs and costs

related to quality of service), in order to allow the regulated firm to achieve the

optimal trade-off between the different types of costs in the selection of inputs.

However, as Borrmann and Brunekreeft (2009) underline, while investments in cost

reduction and replacement, ordinary investments so do speak, may be positively

affected by cap regulation. On the other hand, the “lumpiness” and the “sunken”

nature of cross-border transmission investments, since entail augmented risks and

high cost uncertainty, should be managed by combining, within a hybrid model,

incentive regulation with rate-of-return regulation.

other firms in the industry: X is intended to be a proxy for a competitive market, in industries which are natural

monopolies.

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In this regard, Vogelsang (2001, 2010) proposes a two-period framework

distinguishing a short period and a long period. The short period typically coincides

with the length of a regulatory lag, or of (RPI-X) type adjustments or adjustments

from profit sharing. During the short period the firm makes and executes decisions

on operations, repairs and maintenance costs: a full regulatory commitment and

significant incentives for cost reduction in this short time are feasible. On the other

hand, the long (commitment) period corresponds to the time for revision of (RPI-X)

adjustments and incentive mechanisms at the end of each long period19.

Full regulatory commitment for the time horizon of infrastructure or innovation

investments according to Vogelsang is not possible. Since incentive regulation

concerns shorter time periods than investment, the compatibility of incentive

regulation and efficient investment is in doubt. Incentive regulation for regular

infrastructure investments therefore needs to be updated every few years through

rate-of-return regulation with a used-and-useful criterion This way, short and long

term needs are matched by diversifying both incentives and guarantees, in order to

deliver the most efficient investment.

The literature on this topic is abundant and the debate remains still open, implying

diverging approaches and views on the matter. Léautier, who considers the

unbundling alone insufficient to stimulate investments and hence to reduce

congestion, contends that specific incentives are required to stimulate TSOs to

choose the transmission project that minimizes the sum of the expected congestion

and expansion costs, as well as network losses. For that reason, an alternative

scheme is proposed, by which the regulator offers a “menu of contracts” that would

induce, according to the revelation principle, the transmission company to operate

and expand the transmission system efficiently, while allowing for cost recovery.

Under the proposed scheme, the costs of congestion and expansion become the

responsibility of the transmission company, including a revenue sharing rule that

trades off cost minimization against rent extraction, and an uplift management rule

that induces optimal expansion of the transmission network (Léautier, 2000).

Conversely, some authors argue that efforts should be concentrated on the

optimization of congestion management mechanisms rather than on building new

interconnectors (Nies, 2010), believing that the main question is the inefficient use of

existing cross-border capacity. The issue would concern, for instance, explicit

auctions which do not lead to an optimal use of scarce interconnector capacity, and

19

Cf. I. Vogelsang (2001), Price Regulation for Independent Transmission Companies, Journal of Regulatory

Economics, 20, 141-165; I. Vogelsang (2010), Incentive Regulation, Investments and Technological Change, CESifo

WP No. 2964. Vogelsang’s mechanism works as follows: in times of excess capacity, the variable charge of the

two-part tariff decreases, causing an increase in consumption. The fixed charge, in turn, augments so that total

income increases despite the diminishment of the variable charge. As a consequence, the TSO does not invest

more in capacity expansion and net profits grow since costs do not augment. On the contrary, when there is

congestion in capacity, the variable charge will be a pure congestion charge and, if congestion charges are in the

margin greater than the marginal costs of expanding capacity, the TSO will have incentives to invest in new

capacity.

16

represent a significant barrier to efficient cross‐border trade. Therefore, an

anti‐competitive behavior, such as capacity withholding or inefficient arbitrage by

dominant generators (i.e. trading from a high to a low price area to sustain market

power) is quite possible. For that reason, implicit auctioning mechanisms (i.e. market

coupling) are proposed to facilitate an optimal use of existing capacities, and then

improve the operational efficiency of power commercial exchanges.

This approach delivers an important message but doesn’t solve the problem of the

lack of cross-border transmission facilities. Congestion management is not adequate

enough when urgently needed infrastructure simply does not exist. In this respect,

the realization of the European internal electricity market depends on both adequate

interconnector investments and efficient congestion management.

Today, no first-best solution is available for guaranteeing perfect economic efficiency

in transmission investments, and notably in cross-border ones. Theory and practice

often diverge, and variables are not always manageable. However, one thing

everybody agrees on, cross-border issues should be addressed in a harmonized way

to find a shared approach between countries, and without forgetting that the pan-

European interest is on the top of these investment needs.

“Merchant option”

To foster investments in interconnections the European Commission provided a

“merchant” scheme - laid down in the Regulation 714/2009/EC (repealing Regulation

1228/2003/EC) - alternative to regulated ones, and based on private investors which

identify, construct and/or operate new transmission infrastructures, receiving

remuneration from congestion rents. In this case, investors are exempted from the

requirement of Third Party Access (TPA), keeping the rents arising from congestions,

and TSOs are only involved in connecting these facilities - “merchant lines” - to the

national grid.

This “derogative” option could be an alternative particularly adapted to the

investments in North-South Mediterranean interconnections, represents a strong

incentive to promote cross-border projects, while in the case of regulated schemes

often TSOs have to return rents to grid users by reducing tariffs.

Under the Article 17 of the aforementioned Regulation a merchant investor may be

granted exemptions only if regulated TSOs fail to deliver and if the following

conditions set out here are satisfied: (a) the investment must enhance competition in

electricity supply; (b) the level of risk attached to the investment is such that the

investment would not take place unless an exemption is granted; (c) the

interconnector must be owned by a natural or legal person which is separate at least

in terms of its legal form from the system operators in whose systems that

interconnector will be built; (d) charges are levied on users of that interconnector; (e)

17

no part of the capital or operating costs of the interconnector has been recovered

from any component of charges made for the use of transmission or distribution

systems linked by the interconnector; and (f) the exemption must not be to the

detriment of competition or the effective functioning of the internal market in

electricity, or the efficient functioning of the regulated system to which the

interconnector is linked20.

In this respect, to be fair and beneficial in terms of investments delivering and social

welfare promotion, the exemption regime should be better harmonized in terms of

distribution of decisional powers. Some Member States may be excessively generous

when granting exemptions (cf. EC 2007c), and this risks not only to endanger the

level playing field between TSOs, but also to impede further market integration by

allowing for excessively sub‐optimal merchant interconnectors (Kapff and Pelkmans,

2010).

Generally speaking, merchant investors are better incentivized to build new

interconnectors than regulated TSOs as they face less regulatory uncertainty thanks

to the granted exemptions, while regulated TSO investments suffer from the

additional uncertainty related to the possible change of rates of return in the future.

Nevertheless, some disadvantages in relying on merchant schemes appear from a

social welfare point of view in terms of sub-optimal provision of capacity. Indeed, the

greater the difference in electricity prices between two countries, the greater the

rent obtained by the interconnection provider, hence entailing no incentives to

expand capacity up to the point where prices are equalized.

The merchant (private) optimal transmission capacity - which is necessarily smaller

than the social optimal one – corresponds to the point where the marginal costs of

the project equal the marginal price of congestion. As a merchant investor must

recoup its costs from the exploitation of the trade potential across the

interconnector, he has a considerable interest to keep markets at both sides

“partially disintegrated”, in order to maintain an exploitable price differential (De

Jong, Van der Lippe, and Knops, 2007).

Moreover, as Jacottet (2012) stresses, in a situation where a larger interconnector

would provide maximal social benefit, an interconnector of restricted size (as

provided by a merchant investor) would reduce the economies of scale available from

incremental capacity, making it unprofitable for another investor to complete the job

with a second competing interconnector. In this context, a regulated investment

would be preferable if it were to provide greater capacity. The regulated investor is

less concerned with spot price differentials, as rents above the regulated tariff

cannot (legally) be taken as profits.

20

Cf. Article 17 of the Regulation 714/2009/EC. The decision on exemptions is taken on a case‐by‐case basis by the

concerned NRAs. These may decide – upon joint request or in case of incapability to reach an agreement within

six months – to refer the decision to ACER. Besides, the Commission holds a veto‐right on all exemptions and

may issue guidelines on the implementation of the exemption regime.

18

Therefore, if on the one hand merchant investors may supply more interconnection

capacity in the short term because of their ability to exploit congestion rents, on the

other hand, they have a long term interest in disintegrated markets (the more

congested the interconnector, the more rent can be extracted)21.

***

Regulated and merchant transmission investments represent two different

approaches to deal with the same issue: the lack of cross-border networks.

Merchant transmission could play a significant, but not exclusive role in efficient

transmission expansion by mitigating the problem of under-investment, especially in

a state of regulatory uncertainty. Generally speaking, the regulatory gap between

national legislation and European policy is one of the reasons of the lack of regulated

investments in interconnection.

Both regulated and merchant lines may coexist, and they may complement each

other, but under the existing EU legislation regulated investments are assumed to be

the general rule22.

On the one hand, from an economic point of view merchant transmission does not

provide for optimal grid expansion, mostly due to misaligned incentives: a profit-

driven transmission developer selects the expansion that maximizes the (ex-post)

value of the asset, which does not generally coincide with the socially desirable

expansion (Joskow and Tirole, 2005). Private and public incentives differ.

On the other hand, from a regulatory perspective, there is a real concern regarding

the coexistence of the two investment frames. The risk that perverse incentives

appear for either, TSO or the owner of a merchant line, is real. As a matter of fact,

the construction of a regulated line could significantly impact the revenues collected

by an existing merchant link, so it is crucial to establish a regulatory framework

which deals with the risk that the existence of a merchant line could prevent the

construction of a regulated one23.

Furthermore, as Jacottet (2012) underlines, there exist some licit questionings

regarding the relation between the different degrees of unbundling and incentives to

invest in cross-border electricity interconnections. Indeed, it is arguable that legal

21

Jacottet A. (2012), Cross-border electricity interconnections for a well-functioning EU Internal Electricity Market, Oxford Energy Comment, June 2012, University of Oxford. 22

Cf. Artt. 16 & 17, Reg. EC/714/2009. 23

Merchant lines seem to be limited to some very specific investments where the huge difference in zonal prices

can be sustainable because of some constraints of energy isolation. The example of NYC is paradigmatic, showing

the impossibility to build new generation capacities or to expand interconnectors trough classical terrestrial ways

because of the urban density. Therefore, energy and capacity are expensive in this area. A merchant investor can

benefit from this isolation to connect this isolated area to a close one thanks to non conventional means such as

HVDC lines. Such a merchant line can than benefit from a high and sustainable difference in zonal prices (cf.

Rious, 2006).

19

unbundling creates conflicts, and that full ownership unbundling would give

independent TSOs greater incentives to invest, as the competition it generates in

generation and supply sectors in its home country does not affect the TSO’s holding

company itself. In this respect, it should be noted that all merchant investments so

far in the EU, for example Estlink24 and BritNed25, are financed by holding companies

that also own TSOs: the investors are legally unbundled from the TSOs but have

common ownership. This means that the TSO is still owned by the same parent

company that also owns generation capacity, and in some cases also distribution and

supply companies.

3. New guidelines for European and trans-European interconnections

investments

Today in Europe there is a general increase of investment with respect to the past

(ENTSO-E, 2013). As aforementioned, this is due to three main reasons: hosting

renewables, replacing old assets, and achieving the EU internal market by

constructing interconnections, both European and trans-European ones.

These new investments are related also to the deployment of new technologies (i.e.

off-shore HVDC - as is the case for the submarine cables across the Mediterranean

and in the North Sea - extra high voltage cables, etc.) which is an important aspect

implying risks due to the uncertainty of costs, since the TSOs do not benefit from a

long experience or from any experience at all (Meeus, 2011). Therefore, the

regulatory regime should account for the level of risk and innovation that

investments require (Vogelsang 2010, Müller 2010).

By comparing theory and practice, what emerges today is a lack of an explicit support

for new cross-border investments. Incentives, mostly set for short-term projects,

proved inadequate to stimulate such a long-term investment given the lumpiness

and the irreversible nature of network infrastructures.

Investors are further discouraged by the existence of a “regulatory gap” in terms of

rules harmonization, worsened by the fact that each regulator only has authority

within its national perimeter and no authority really regulates and oversees

cross‐border and regional issues. There is no supra‐national authority responsible

for the cost allocation of cross-border projects - for instance, deciding on a

compensation for transit country - and investors face an important risk of project

24

Estlink is a set of HVDC submarine power cables between Estonia and Finland.

Estlink 1 is the first interconnection between the Baltic and Nordic electricity markets following by Estlink 2 in

2014. The main purpose of the Estlink connection is to secure power supply in both regions to integrate Baltic and

Nordic energy markets. 25

BritNed is a high-voltage direct-current (HVDC) submarine power cable between the Isle of Grain in Kent, the

United Kingdom; and Maasvlakte in Rotterdam, the Netherlands.

20

failure when the concerned national regulatory authorities are unable to agree on

key cross-border regulatory provisions.

Various steps have been taken to encourage a more consistent approach to

regulation across the EU, both at the institutional and regulatory level. In 2011 a new

European agency - the Agency for the Cooperation of Energy Regulators (ACER) –

was established to deal with Europe’s pressing demands for a more closely

integrated energy market26. And in 2013, the European Commission adopted a

regulation on guidelines for a trans-European energy infrastructure to reduce risks

and accelerate the networks deployment. However, for what concerns investments in

cross-border interconnections, the powers of the Agency are still limited to a mere

role of coordination between Member States, without any effective coercive authority.

To compensate this “institutional lack”, and given that regulatory regimes with

heterogeneous economic properties could actually hamper investments with

regional impact, a more harmonized scheme for investors in regulated utilities

becomes crucial at least to minimize their cost of capital. As earlier stressed (cf. Box

n. 3), reinforce the confidence by improving stability of regulatory regimes helps to

reduce the premium asked by investors to inject their money in regulated utilities.

Hence, even though ACER still has limited powers, it might play an active role by

formulating “good practice guidelines” regarding the regulation of transmission, in

order to promote sound regulatory practices that could help to minimize the risks for

investors and to share the knowledge accumulated by best/bad practices (Glachant,

Saguan, Rious, Douguet, 2013).

Completely separate internal and cross border investments in electricity network is

not possible since cross border capacities also need investments inside the national

networks. So, in the context of a common regional market a certain degree of

alignment on the economic properties of the existing regulatory regimes is

necessary. In this regard, the harmonization of incentive mechanisms is essential to

ensure a good coordination between different investments27.

However, this does not imply that all the regulatory design options, parameters or

revenue components should be exactly the same, but at least that the regulatory

preferences and the economic properties influencing the network investments are

aligned to a certain extent: “some diversity in regulatory practices can provide

valuable insights into functioning models and might allow to discover best (and bad)

practice for specific situations” (Ruester 2012).

As for the existing regulatory options, the traditional mechanisms (i.e. cost-plus and

cap models based on RPI-X methods) have proved to be insufficient to promote

26

ACER took over the work of ERGEG (the European Regulators’ Group for Electricity and Gas) which was an

advisory group to the EC on internal energy market issues in Europe. 27

A typical example of the problem of misalignment is when one TSO is highly incentivized to push the cost of

internal congestion at the border (hence on the cross-border flows) while discouraging the cross-border

investments (Glachant & Pignon 2005).

21

investments in interconnections mainly because designed for national transmission

investments. Furthermore, a lack of supra‐national network planning impeded until

now a right identification of the most beneficial investment project. To cope with

these deficiencies regulation should find a new balance between incentives for cost

reduction and risks born by TSOs on the one hand, and between the remuneration of

investments and the transfer to final users on the other.

In this respect, since the main regulatory goal is to reduce the cost of capital and to

ensure favorable financial structures, this new equilibrium between TSO investment

risks and TSO incentive for cost efficiency must be found through the establishment

of new criteria that allow for a more specific evaluation of interconnection projects, in

order to prove their real need, gain the social consensus and obtain funds.

Two innovative devices, partially integrated in the new ENTSO-E methodology for the

system-wide evaluation of new projects and in the Regulation No. 347/2013/EC, have

been recently proposed both, for a better estimation of investment costs and for a

more efficient decision-making procedure: the cost-benefit analysis and the

proactive behavior of TSOs.

The cost-benefit analysis

The project Realisegrid, co-funded by the European Union (EU) within the

7th Framework Programme, investigated new criteria, methods and tools to assess

how the transmission infrastructure should be optimally developed, and proposed

among other things to implement a cost-benefit analysis in order to establish a

proper foundation for a correct evaluation of investment efficiency. When evaluating

individual projects, a utility function should translate outcomes into monetary terms

and eventually create a mono-dimensional ranking that enables the best solution to

be identified.

Such an approach is supposed to provide the basis for an “incentivization” factor that

may contribute to highlight the transmission investment optimality. In this regard,

the optimal way to measure the investment economic viability, and consequently

establish a “prize” for the entity that brought it, would be to estimate, on the basis of

the actual market prices and transits on the new interconnector, what increase in the

social welfare; or other benefits that can be translated into monetary terms and

actually be obtained over a certain period of time, following the entrance into service

of the infrastructure.

The advantages of the new infrastructure (in terms of difference between benefits

and costs) should be calculated at the time at which the investment decision is made.

This would be done by assessing, by means of two system simulations (one with the

new infrastructure and one without), the impact of the new interconnector in terms of

benefits minus costs. This indicator will constitute a KPI (Key Performance Indicator)

22

in percentage to which an increase in the return of investments of the TSO could be

calculated.

However, this approach cannot neglect the environmental constraints, which

represent a very influential factor in limiting interconnection improvements. For this

reason projects involving new structures and facilities will be more difficult,

expensive and time consuming than those for upgrading the existing facilities where

the environmental resources have already been exploited. In this respect, the cost-

benefit analysis should internalize the environmental constraints which often are

related to political factors, rather than to technical or financial issues, taking the

shape of the opposition of “local interests”.

The proactive behavior of TSOs

The liberalization process produced asymmetry on investments coordination

engendering bottlenecks and delays, particularly when the regulatory environment is

such uncertain about future evolution. Moreover, most of the transmission capacity

expansion projects are capital-intensive and time-consuming, with a considerable

impact on the environment, which implies some concerns of social acceptance

entailing further delays and potentially jeopardizing the realization of projects. In this

regard, the cost-benefit analysis could also be combined with a proactive behavior of

the TSOs in their investment approach.

As Rious, Glachant and Dessante (2010) state, a TSO should be proactive and play in

advance so as to reduce the gap between the time when new generation is installed,

and the time when the necessary infrastructure is operational. The evaluation of the

probability that a new generator requesting connection will become operational is

part of the TSO risk assessment for purposes of demand forecasting. Thus, the key

issue is how evaluating the efficiency of the proactive behavior for a TSO from a

social point of view, considering the anticipation costs.

The connection of a generator to the grid is a probabilistic event because of market

uncertainties and administrative delays and/or refusals28. Besides, as mentioned

before, the time interval between the generation (2 or 3 years for some technologies

as CCGT and wind farms which stand for the biggest amount of generation

investments in EU) and transmission investments (7 or even 10 years in Europe) can

create congestion, implying costs affecting the social welfare. Therefore, a risk

assessment which takes into account three essential parameters: the anticipation of

investment costs, the probability of connecting generation and the time difference for

building such infrastructures, seems to be the right way to go.

28

The duration of the administrative procedures required before the construction of a power line stands for

almost three quarter of the construction time.

23

Such a proactive behavior is expected to create a virtuous circle giving better

information to market participants by signaling new opportunities to locate

generation capacities. This approach should be included in the regulatory framework

through some incentive mechanisms encouraging TSOs to bear the risk. Again, to

avoid inefficiencies or failures, the regulator has to mold the market design by a

dynamic approach which implies the adaptation of regulation to the industrial

development in a liberalized environment.

The Ten-Year Network Development Plan (TYNDP)

Regulation 714/2009/EC establishes that ENTSO-E has to submit to the ACER and the

European Commission the methodology, including on network and market modeling,

for a harmonized energy system-wide evaluation at Union-wide level for projects of

common interest. The results will be used by the concerned National Regulatory

Authorities (NRAs) to decide the allocation of investment costs among the concerned

TSOs.

ENTSO-E published the final 2012 Ten-Year Network Development Plan (TYNDP)

package on July 5th and submitted it to ACER for opinion after having conducted

a web-based public consultation on the reports from 1 March until 26 April 2012, in

line with the Regulation.

The TYNDP package comprises of six detailed regional investment plans and the

Scenario Outlook & Adequacy Forecast (SO&AF) 2012–2030, as well as the pan-

European TYNDP 2012 report, providing a structured, systematic and comprehensive

vision for grid development in the coming 10 years in Europe.

The presentation of projects in the TYNDP 2012 has been organized to display both a

synthetic technical description of every project item and the cost benefit analysis of

every project. Transmission projects are valuated against the following multi-criteria

scale developed by ENTSO-E:

Principles of multi-criteria assessment of projects of pan-European significance

Source: ENTSO-E (TYNDP, 2012)

24

Projects basically improve the grid transfer capability and an assessment of the grid

transfer capability increase is provided for every project. All other dimensions are

evaluated via 3-level indicators:

- The social and economic welfare indicator, the RES integration indicator and

improved security of supply value the benefits of the projects in the 3

dimensions of the EU energy policy (market integration, RES development and

Security of supply.

- The RES integration, losses variations and CO2 emissions variation indicators

value the benefits with respect to the three pillars of the 20-20-20 policy.

- The technical resilience and flexibility indicators refer to the technical

performance of the assets in the grid.

Moreover, the community-wide Ten Year Network Development Plan identifies the

required investments for the near future and clearly indicates that from a financing

perspective the investment challenge is significant in two ways:

- Investment size: The overall size of investments, i.e. the overall budget

required to accomplish the envisaged transmission infrastructure is

unprecedented and requires attracting more capital to the transmission

infrastructure business.

- Investment pace: Not only the overall investment size is huge and challenging,

also the timing to deliver those new investments is challenging. The pace of

investments required to meet the European policy objectives is higher than

common investment rates in the recent past. Annual investment budgets have

to increase in order to deliver the needed infrastructure within the required

timeframe

In this regard, to foster investments a coherent long-term EU energy policy would be

essential for a more correct estimation of the different projects. To attain this

objective the European Commission officially approved on 27 November 2012 the e-

HIGHWAY2050 project, with the aim to develop a top-down planning methodology

providing a first version of a modular and robust expansion of the Pan-European

Network from 2020 to 2050, in line with the European energy policy pillars29. Besides,

following the conclusions of the European Council of 4 February 2011 which

underlined the importance of streamlining and improving permit granting processes

while respecting national competences, in October 2011 the European Commission

proposed a regulation on guidelines for a trans-European energy infrastructure

(European Commission, 2011a), later adopted in 2013 (Regulation No. 347/2013/EC).

29

The results of the project will be presented and debated throughout the project with the whole electricity value

chain as well as representatives from all the impacted stakeholders in Europe, thus addressing the main drivers

and potential barriers for the proposed grid architecture options.

25

Regulation No. 347/2013/EC: Projects of Common Interest (PCI)

The Regulation No. 347/2013/EC lays down guidelines for the timely development and

interoperability of priority corridors and areas of trans-European energy

infrastructure30. Even though it cannot mitigate by itself the issue related to the

heterogeneity of the existing regulatory regimes, however the Regulation contains

measures contributing to reduce risks and accelerate network deployment, in

particular:

- addressing the identification of projects of common interest necessary to

implement priority corridors;

- facilitating the timely implementation of projects of common interest by

streamlining, coordinating more closely, and accelerating permit granting

processes and by enhancing public participation;

- providing rules and guidance for the cross-border allocation of costs and risk-

related incentives for projects of common interest;

- determining the conditions for eligibility of projects of common interest for

Union financial assistance (access to EU funding through the “Connecting

Europe Facility” - more than half of the €9.1 billion the facility dedicates to

energy infrastructure is expected to be available for electricity projects).

Regulation 347/2013/EC establishes nine strategic geographic infrastructure priority

corridors in the domains of electricity, gas and oil, and three Union-wide

infrastructure priority areas for electricity highways, smart grids and carbon dioxide

transportation networks, introducing a transparent and inclusive process to identify

concrete projects of common interest (PCIs), which are needed to implement the

priority corridors.

This process is based on regional cooperation, involving all relevant parties in the

field of energy, who deliver their knowledge and expertise with regard to the

technical feasibility and market conditions, both from a national and a European

perspective. Stakeholders include transmission system operators (TSOs) and other

project promoters, ministries, national regulatory authorities (NRAs), the European

Network of Transmission System Operators in gas and electricity (ENTSO-E and

ENTSOG), the Agency for the Cooperation of Energy Regulators (ACER), the

Commission, and observers such as the Energy Community.

A project to be considered of common interest shall meet, among others, any of the

following criteria:

- involves at least two Member States by directly crossing the border of two or

more Member States;

- is located on the territory of one Member State with a significant cross-border

impact;

30

Cf. Art. 1

26

- crosses the border of at least one Member State and a European Economic

Area country.

- contributes to market integration (by lifting the isolation of at least one

Member State and reducing energy infrastructure bottlenecks), competition

and system flexibility;

- facilitates the integration of renewable energy into the grid and the

transmission of renewable generation to major consumption centers and

storage sites;

- improves the interoperability, through appropriate connections and secure

and reliable system operation.

A project with significant cross-border impact is expected to increase the grid

transfer capacity, or the capacity available for commercial flows, at the border of that

Member State with one or several other Member States, or at any other relevant

cross-section of the same transmission corridor having the effect of increasing this

cross-border grid transfer capacity, by at least 500 Megawatt compared to the

situation without commissioning of the project31.

Concerning market integration, competition and market flexibility, such indicators

have to be estimated, for cross-border projects, calculating the impact on the grid

transfer capability in both power flow directions, measured in terms of amount of

power (in megawatt), and their contribution to reaching the minimum interconnection

capacity of 10% installed production capacity or, for projects with significant cross-

border impact, the impact on grid transfer capability at borders between relevant

Member States, or between relevant Member States and third countries32.

However, it must be emphasized that North-South interconnectors are not subject to

EU legislation, but only to national legislations in the North and South countries. In

almost all cases, national legislations concerning North-South interconnectors are

rather vague. In this regard, measures introduced by Regulation 347/2013/EC are

expected to be highly beneficial to North-South Interconnector projects. Their

promoters should apply to the PCI selection process, and participate actively,

together with the TSO of the third country concerned, in the corresponding regional

group led by the European Commission. Two regional groups are relevant for North-

South interconnector projects, corresponding to two priority corridors: “North-South

electricity interconnections in Western Europe” and “North-South electricity

interconnections in Central Eastern and South Eastern Europe”.

Particular attention should be paid to showing that a North-South interconnector

project involves at least two member states (a condition required for a project to be

considered as a PCI): it allows for delivery of energy from renewable sources in a

31

Cf. Regulation 347/2013/EC. 32

Ibidem.

27

third country not only to one Member State, but to several countries of the EU33. In

the first PCI selection process (2012-2013), candidate projects may be considered

separately from the Community-wide TYNDP. From 2013 onwards, candidate

projects will have to be included in the TYNDP (the next one in 2014) prior to the PCI

selection.

33

This can be checked, as required by the European regulation, by showing the capacity increase brought by the

interconnector at an essential cross-section of a North-South priority corridor

28

Box 3. TSOs and financial issues

The ten-year plan established in 2012 by the European Network of Transmission System

Operators for electricity (ENTSO-E) identified investments of €104 billion to be spent in the

next ten years on projects of pan-European significance alone. The life of transmission

assets is on average 40 years, and high upfront costs must be covered at times of

investment while pay-back is delivered though a low return over a long period. In this

regard, even in case when profitability in the long-term is ensured, TSOs still need to raise

the money initially.

Full harmonization of remuneration schemes for transmission is extremely difficult, as it

requires changing high level regulation in most countries. Therefore, given that at the

present it is unclear if regulated TSOs will be able to cope with the substantial amount of

investments - unprecedented since liberalization - it should be necessary to reduce the

financial risk of such projects as much as possible, since uncertainty in cost recovery is

presently a major deterrent to transmission expansion, affecting directly the TSO credibility

at the financial level.

Indeed, TSOs are natural monopolies on the national level, but on the international financial

markets they are like all other actors, in competition to find loans and thus rely on the same

financial market conditions. Equity and debt finance will only be available to utilities

(whether they are private or public ones) who agree to credit conditions posed to firms that

operate in competitive industries with a comparable credit ranking.

Raising external equity is an attractive option when the debt level has to be kept under a

given threshold. Yet it is also a more expensive option. In addition to higher costs, there are

two main obstacles to financing investments by injecting external equity, due to the fact that

most European TSOs are still publicly owned34. On the one hand, European States are not

“liquid” at the present time because of the consequences of the financial crisis and the

economic downturn. As stressed by Helm (2009), States facing budgetary constraints prefer

to protect operational expenditures (OPEX) and reduce capital expenditures (CAPEX). On the

other hand, States might be reluctant to dilute their ownership share of crucial assets with

major public goods properties (Henriot, 2013).

Given the capital-intensive nature of electricity networks, the return on asset accounts a

significant share of the allowed revenue and, as relatively small changes to the rate of

return can have a significant impact on the total revenue requirement and investment

behavior of the companies, it is essential that the regulator sets the rate of return at a level

that reflects an adequate commercial return for the regulated companies. As D. Dobbeni35

stresses, regulatory uncertainties and low tariffs produce negative externalities on

investments because they contribute to reduce the confidence of financial markets. The

financial risk of transmission investment should be tackled as much as possible, since

uncertainty in investment cost recovery is presently a major deterrent to transmission

expansion.

34

Even in situations of private ownership (as in Belgium, Italy and Spain), public entities still hold a large minority

share. 35

Former President of ENTSO-E.

29

The potential mismatch between the basis on which regulators determine allowed returns

and the criteria used by financial markets in assessing alternative investment opportunities

is perhaps the most important factor affecting future investments in utility infrastructure.

So a key question is how regulators trade off the apparent short term “efficiency” in capital

structures which results from gearing up against longer term robustness.

In this regard, if on the one hand cross-border transmission investment incentives provided

by Member States can take the form of direct subsidies, or indirectly of low‐interest or

interest‐free loans; on the other hand, such selective aid measures risk being qualified as

prohibited state aid. Regarding that, it is important to mention that aids for “important

projects of common European interest” are compatible with the internal market in

accordance with art. 107 (3-b) TFEU, showing that this derogation could be a way to follow.

However, it is improbable that Member States will rely on such costly scheme because

investments in interconnections typically generate positive cross-border externalities whose

benefits are hardly collectable. Besides, incentives of individual countries might not be

aligned with overall welfare improvement when considered from a wider regional

perspective.

For these reasons, as the European Commission underlines, investment funding is better,

but the existing gap in private financing should be bridged by making even more use of the

EU budget than is currently the case today, using innovative financial instruments as

European funds that could be used in partnership with the banking and private sectors,

specifically through the European Investment Bank (EIB)36.

For projects of “European interest” which have no or poor commercial viability, innovative

funding mechanisms should be proposed for maximum leverage of public support to

improve the investment climate in order to cover the main risks or to speed up the projects

implementation37. In this respect, a first step has been made through the adoption of

Regulation No. 347/2013/EC which introduced some measures to reduce risks and

accelerate network deployment, in particular for PCIs (Projects of Common Interest), which

once identified would benefit from: (i) faster permit granting procedures; (ii) improved cost-

allocation procedures leading to longer-term incentives; and an access to EU funding

through the “Connecting Europe Facility”.

However, as Henriot (2013) shows in his recent study, due to their current financial

situation, and under historical trends in transmission tariffs, TSOs will not be able to achieve

more than half of the investment plans. Higher capital expenditures would result in financial

degradation of TSOs and a rapid loss of their investment grade. Thus, even though

alternative financing strategies, such as issuing additional equity, restraining dividends, or

reducing risks by improving regulation could help achieving the whole-scale investment

volumes at lower costs for consumers, tariffs will have to increase significantly if the totality

of the investment plans is to be met.

In this respect, as stated in a recent position paper38, ENTSO-E welcomes the efforts already

made in this area such as certain provisions for incentives outlined in the Energy

36

COM (2010) 608 final, Towards a Single Market Act. For a highly competitive social market economy. 37

COM (2010) 639 final, Energy 2020: a strategy for competitive, sustainable and secure energy. 38

ENTSO-E Position Paper (23-05-2013) Incentivizing European Investments in Transmission Networks.

30

Infrastructure Regulation, the budgets foreseen in the Multi-Annual Financial Framework

and the restructuring of financial support mechanisms in the Connecting Europe Facility.

Nevertheless, ENTSO-E warns that these efforts are insufficient to meet the challenge and

calls for further action on risk reduction as well as remuneration, by creating a framework

recognizing the particular financial needs of TSOs. Such a framework goes beyond the

national regulatory framework and needs a European component which should not be

limited to improving debt financing options or grants, but also should incentivize equity

financing. According to ENTSO-E, without extra incentives for equity financing, both the size

and the pace of the investment challenge remain out of reach. The attractiveness of the

electricity transmission sector and in particular the risk-reward balance of the prioritized

projects necessary to meet the EU goals should improve in order to be competitive at global

capital markets.

Reducing risks and enhancing equity financing are complementary measures. To convince

investors to finance complex projects, it does not suffice to only reduce risks when projects

are labeled as priorities. Adequate and attractive remuneration must also be a prerequisite.

Risk reduction is a typical national framework matter. To achieve certain European

performance targets, a common overarching incentive should be fostered in addition to

those country-specific regulatory measures to balance the higher risk related to this kind of

investments.

Therefore, improving return on equity is crucial. This should be tackled at the European

level. In this respect, ENTSO-E considers that a priority premium mechanism, i.e. “an add-

on or supplement on the typical TSOs’ rate of returns, is an efficient and effective solution to

differentiate returns and foster the required investments in a timely manner. According to

ENTSO-E the leverage capability of priority premiums in raising funding fits with the aims of

the Connecting Europe Facilty (CEF)”39.

***

Given the scale and urgency of transmission network development, it is vital to

ensure that efforts to promote infrastructure investments involve also the

Mediterranean area, benefits being not negligible. To facilitate the discussion with

the European Union on Projects of Common Interest, Medgrid and OME recently

recommend in their last publication “Towards an Interconnected Mediterranean

Grid”, to develop a “Mediterranean-wide Ten-Year Network Development Plan”,

similar to the “Community-wide TYNDP” developed in the EU. The methodology

introduced by the regulation on trans-European Infrastructure, based on a data set

“representing the Union's electricity (…) systems”, should be enlarged to all

Mediterranean countries, for a “Euro-Mediterranean-wide” cost-benefit analysis.

The methodology shall define the analysis to be carried out, based on the relevant

input data set, by determining the impacts with and without each project. The area

for the analysis of an individual project shall cover all Member States and third

39

Ibidem.

31

countries, on whose territory the project shall be built, all directly neighboring

Member States and all other Member States significantly impacted by the project.

The Mediterranean TYNDP, possibly updated every three years, should show the

long-term needs for the transmission grids around the Mediterranean Sea, and

identify bottlenecks, mainly on interconnectors (North-North, North-South and

South-South), but also possibly in internal grids. The objectives and procedures of a

Mediterranean TYNDP should be defined in close cooperation with MedReg and Med-

TSO.

32

Box 4. The Italian Experience

As for the latter, in order to incentivize and speed up the delivery of transmission

investments, the Italian Regulator has introduced a set of incentive mechanisms. The main

one, set by Resolution 348/07, provides additional RAB remuneration (2% or 3%, for 12 years

from the entry into service) on specific classes of development projects (those with the

higher public benefit, mainly aimed at internal congestion resolution or at enhancing cross

border capacity). An ancillary incentive mechanism, set by Resolution 87/10, allows the

Italian TSO to also receive the extra RAB remuneration on work in progress (hence before

the entry into service of the projects) for a subset of said projects, provided that each year

the TSO respects at least 70% of a set of project milestones. The mentioned milestones

need to be proposed ex-ante by the TSO and are approved by the Authority.

The same Resolution also introduces a mechanism which triggers an additional per-project

reward or penalty in case of early or late project completion. The overall system encourages

Terna, the Italian TSO, to focus on the timely delivery of priority projects, aiming to align the

TSO’s incentives with the customers’ priorities.

The Italian mechanism has been successful in triggering investments as indicated in the

figure below, elaborated by ENTSO-E in 2013:

Fig A. Effect of equity adders on incentives in Italy (ENTSO-E, 2013)

Source: Roland Berger, 2011.

33

Conclusion

The environment in which the electricity transmission networks operate has changed

considerably, with consequences in terms of regulatory measures, which have to be

adopted in a context increasingly articulated. Today, the main objectives are to

strengthen the Internal European Energy Market (IEM), and progress towards a more

integrated grid across Mediterranean countries. To reach these targets and improve

the regional integration of electricity systems, with benefits in terms of renewables

integration and security of supply, some fundamental investments are required,

notably the construction of additional cross-border transmission capacity between

EU Member States, across the Mediterranean through submarine cables, and

between SEMCs (South and Eastern Mediterranean Countries).

The challenge is important and complex, and a common regional approach involving

all the Euro-Mediterranean TSOs, as well as the related national regulatory

authorities (NRAs), is fundamental (OME-MEDGRID, 2013). In this respect, a

supra‐national network planning, as the one drawn by ENTSO-E, should be

delineated at the Mediterranean level and in a coordinated way by MED-TSO, with the

involvement of MEDREG. To do that, a shared system of technical rules and

information procedures, taking into account the specificities of each country, is

fundamental to foster the development of interconnected grids.

However, even though additional cross-border transmission capacity is crucial to

further integrate electricity systems, a “regulatory gap” hampers interconnector

investments both in EU and in the Mediterranean region. In this context, where the

identification of the new infrastructures takes a regional scale, a framework

recognizing the financial needs of TSOs (cf. ENTSO-E, 2013) and appropriate

incentives are necessary to foster investments and deliver infrastructures rapidly.

At the present, incentives provided by the market in EU are proved inefficient, and a

strong political and regulatory support becomes more and more important. In

particular, priority premiums for projects of common interest seem to be an efficient

way to enable developers, in such a current political and economic situation, to

access the necessary capital (equity and debt).

In this respect, priority premiums that are not new and have proven useful to boost

investments in the US and Italy, seems to be a good incentive to attract investors in

TSOs as they would be enabled to offer higher rates of return, limiting the number of

projects to be co-financed (as the priority premium concept would in some occasions

replace direct EU participation in project expenses), and incentivizing EU wide

common prioritization of specific projects. This makes priority premiums a cost

effective way of incentivizing investments with moderate impact on the customers’ or

taxpayers’ bill, even though it should be acknowledged that the PCI process will

34

result in extra costs made by TSOs, which should be accepted by the NRAs when

regulating the tariffs (ENTSO-E, 2013).

According to ENTSO-E, reducing risks and enhancing equity financing are

complementary measures40. To convince investors to finance complex projects it

does not suffice to only reduce risks when projects are labeled as priorities, but in

this respect providing adequate remuneration, in terms of a common overarching

incentive at European level, is a prerequisite as well. Furthermore, ENTSO-E

believes that a priority premium mechanism is an efficient and effective solution to

differentiate returns and foster the required investments in a timely manner.

For the selection of projects the cost-benefit analysis developed by ENTSO-E should

take a Euro-Mediterranean dimension. However, even though this methodology can

be useful for purposes of cross-border cost allocation for some projects of particular

characteristics (e.g. electricity highways), for the cost allocation of the vast majority

of projects it can be counter-productive, since experience has shown that mutual

agreements between TSOs and Regulators are often a simpler and more efficient

way to allocate costs (ENTSO-E, 2013).

According to ENTSO-E, it is important that regulation clarifies that costs are

allocated through a mutual agreement between project promoters and national

regulators, and that the cost-benefit analysis comes as an assisting tool in case of no

agreement. Indeed, there exist elements that are not known ex-ante, as congestion

rents or the inter-transmission system operators’ compensation mechanism, that

impose a multi-criteria methodology, as the one proposed by ENTSO-E.

Regarding merchant lines, which represent an exception to the EU general rule, they

should be encouraged only when regulated TSOs fail to deliver sufficient

interconnection capacity, ensuring that regulation limits the adverse effects related

to the intrinsic sub‐optimality that merchant investments may produce.

Given the scale and urgency of transmission infrastructure development, it is vital to

ensure that efforts to promote infrastructure investment are not limited to PCIs. In

terms of regulatory incentives for TSOs, a more holistic approach is needed, going

beyond discussions on rates of return. The challenge rather lies in incentivizing the

right kinds of investments, with solutions crucially depending on the regulatory

framework within Member States, which should be predictable and transparent.

More specifically, the regulatory framework for congestion management should

encourage the investment needed for both, RES-E integration and the completion of

the internal market for electricity. Further note, merchant projects for new

interconnectors also should have a fair opportunity for development.

40

Ibidem.

35

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