The increasing dependence on remote sources of natural gas and the growing demand for energy in Europe – together with security of supply and environmental concerns – call for a wave of investments in energy infrastructures in most European countries. Furthermore, the development of an integrated pan-European transportation system – both in gas and electricity – is seen as a necessary condition for the development of competition within the European wholesale energy markets.
These network upgrades are to be planned in the context of liberalized markets characterized by high degrees of uncertainty. In order to govern network development, the European regulation points at a hybrid system where System Operators (SO) and Regulators will have to coordinate their planning activity with the developments of the market, in terms of demand, supply, system adequacy and merchant investments in energy infrastructures. Member States will enjoy wide discretion on how to set up the decision-making process and allocate the risks of the new investments. In this respect, the default framework in the Directive is the traditional one, which places all the risks on final customers, who bear the cost of all the investments selected by the SO and approved by the Regulator, irrespectively of their actual use and usefulness. However, merchant infrastructures will also be allowed and, particularly in the gas sector, the development of new transmission pipelines will have some market-based features.
In spite of the priority assigned to the deployment of a coordinated investment plan, the methodological framework which is used to assess infrastructural upgrades in the EU is still largely undetermined. The available literature often focuses on specific issues, such as competition or system adequacy, without putting all possible costs and benefits in a unified framework.
This CERRE Energy & Climate report addresses this crucial topic, providing a comprehensive methodological framework in order to assess the impact of transmission upgrades, covering also the elements of the regulatory and organizational framework that may directly impact the effectiveness of the investment selection methodology, ranging from the definition of transportation rights, to transmission tariff design, to trading arrangements.
Further, in a context in which investment decisions are still taken – to some extent – on a national basis, the report addresses the issue of how the investment costs could be shared among different countries.
The methodology we propose allows for the assessment of the impact on social welfare of any transmission upgrades, by simulating the market outcome with or without the new infrastructure. Moreover, environmental externalities and security of supply concerns are taken into account in the simulation and assessment process.
Within a unifying methodological framework, we have considered two different approaches to take into account the distinguishing features of the gas and electricity sectors. For the electricity sector, the assessment is mainly based on a Security Constrained Optimal Dispatch Model, which simulates a cost-effective equilibrium between supply and demand. For the gas sector the assessment is also based on a cost-effective simulation of the market equilibrium, but with a different approach. The difference between electricity and gas stems from the high degree of uncertainty related to the model inputs. For instance, predicting gas flows across a central European country requires assessing the procurement sources of all the surrounding countries and, ultimately, how supplies to Europe will be shared among the main producers. Moreover, the relation between production costs and market prices is particularly complex and different estimations might lead to different results. To overcome these issues, we propose a hybrid decision-making process, designed in such a way that the SO and the Regulator can extract as much information as possible from the market. In this hybrid institutional setting, the assessment of the value of the gas transmission upgrades is based on the availability of market investors to take on some of the corresponding risk.
Our analysis is based on the assumption that the SOs are “benevolent”, i.e. they maximise the relevant notion of social welfare without pursuing any private agenda. This rules out of our analysis any issue related to the incentives for the SO to select the optimal set of network upgrades. Having ruled out any SO-incentive issues, we consider regulatory systems and investment selection methodologies that place no risk on the SO. In fact, we see no basis to place risk on the SO if not within the context of an incentive-based regulatory scheme. As a consequence, the alternative approaches that we have considered differ in the way they split the investment risk between final customer and the transmission network users.
Adapted cost-benefit analysis
The prevalent role of the central decision-making by the system operators and the industry regulators, within the European context, makes the assessment of the costs and of the benefits of network upgrades crucial.
The cost-benefit analysis (CBA) is a set of standard analytical tools applied by local, national and international development agencies to evaluate policies, programmes, projects, regulations, and infrastructural investments. A key concept underlying CBA is that observed prices may not provide the correct measure of a project’s contribution to social welfare and investment decisions taken on such basis may lead to a socially undesirable outcome. The market process may fail to result in welfare maximizing production and investment decisions due to market or regulatory failures. The way to address those imperfections in the standard CBA is to apply corrective factors to the input and output prices, in order to reflect the real costs and benefits respectively incurred by and accruing to society.
We propose to adapt the standard CBA methodology in order to take into account the specificities of the electricity and gas sectors, as well as the European economic and institutional environment. In Europe, the energy regulators’ mandate is typically narrower than the one assumed in the standard CBA. The regulator’s objective function is typically limited to maximizing the total surplus created in the industry and not in the entire economy. Other institutions and policies address issues such as growth, inequality, employment etc. On the other hand, the way the surplus generated in the industry is split between consumers and suppliers is highly relevant in the regulator’s agenda. Much of the regulator’s action relates to preventing the exercise of market power, not only because of its adverse effects in terms of total surplus generated in the industry but, above all, because of its welfare distribution implication. Finally, environmental sustainability objectives impact on the regulator’s decisions but are not set by the regulator; from the regulator’s point of view they can in a sense be interpreted more as constraints than as objectives.
These features result in three broad methodological implications. First, the proposed methodology refers to a welfare function whose scope is limited to the gas or the electricity industry. This means, for example, that our analysis does not assess the impact of the energy transmission infrastructure upgrades on the surplus created in the wire and pillar industries. Second, we take the actual investment costs and the current prices for the outputs to represent the correct economic values. Third, the financial analysis, central in the standard CBA, does not play an important role in our setting. In fact, in a central planning framework, investment costs are passed on to the electricity and gas consumers via tariffs. Therefore, once the desirability of the investment is assessed based on the comparison between benefits and costs, financial issues are addressed in the tariff-setting process.
The transmission network is an input to electricity and gas supply. For that reason, assessing the value of transmission upgrades requires estimating the changes in the market outcomes induced by the additional transmission capacity. The methodology to assess the impact of the network upgrades on the market outcome is different for the electricity and for the gas sector.
Electricity transmission investments
A significant part of the benefits from transmission upgrades results from their impact on generation and ancillary services’ costs. However, other types of benefits should be taken into account as well when assessing the welfare impact of a new transmission line. First of all, the infrastructural upgrade is likely to improve the system adequacy. Other benefits may arise from the possibility of connecting and dispatching a higher quantity of renewable sources, as well as from a reduction of Green House Gas (GHG) emissions. All these types of benefits are typically interdependent and should be assessed simultaneously.
We propose to base the assessment of the value of electricity transmission investments on a Security Constrained Optimal Dispatch (SCOD) model. The SCOD allows to forecast the wholesale market outcome “with and without” the proposed network upgrade and assess most of the effects of the transmission upgrade simultaneously, ranging from electricity prices, to network losses, from emissions to system security. Depending of the specific features of the implemented model, some effects may have to be assessed partially off-model. Typically the assessment of the effects of the network upgrades on the generator’s market power and on system reliability require some off-model analysis.
SCOD allows for a clear identification of the hypothesis stated in terms of the evolution of installed generation capacity under different scenarios. Such modelling can be done applying optimization techniques to the constrained optimal dispatch problem. Power injections of generators are chosen to minimize the total generation costs to meet demand, while satisfying the security constraints on the resulting power flows.
The assessment is carried out with reference to a market mechanism that determines the most efficient use of the available network resources in a short time frame, typically hour-by-hour. In that setting transmission rights are allocated “implicitly”, within the process that determines the minimum set of costs that generators will produce.
The SCOD can be used in order to simultaneously assess the following impacts of the network upgrades:
- Changes in generation costs;
- Changes in ancillary service costs;
- GHG emissions reduction;
- Changes in the amount of renewable generation.
Other benefits, such as reliability and reduced losses, should be assessed independently, at least in an initial phase.
In our proposed approach, the methodology to assess the cost of the network infrastructure does not depart from the methodology that a private investor would follow to forecast the cost of a large technical infrastructure, as in the adapted CBA.
Accounting for security of supply in the electricity sector
Security of supply, in the electricity industry, depends on the availability of primary sources for electricity production and on an adequate level of installed generation capacity. Security of supply objectives are reflected in the SCOD assessment, as they impact the evolution of the generation capacity installed in the system, which is an input to the SCOD model.
Accounting for market power in the electricity sector
In the SCOD model the level of the generators’ price bids used has been assumed to be reflective to the generators’ variable cost. However, generators may enjoy market power, i.e. they may have the ability and the incentive to set prices, deviating from competitive levels. Binding transmission constraints within a single coordinated market result in fragmented geographic sub-markets, in which market concentration is often higher than at the broader market level. Thus, transmission upgrades may generate benefits by expanding geographic sub-markets and thus decreasing the generators’ market power.
We propose the assessment of the impact of transmission expansions on market competition off-model. Namely, by: a) calculating the measures of market power of each market player and b) applying bid mark-ups that reflect the market power measured by those indicators.
Gas transmission investments
The general framework for a cost-benefit analysis of a gas transmission investment does not conceptually differ from the one discussed for the electricity network investments. In particular for gas as well as for electricity the value of a transmission upgrade is, in general terms, the net surplus of the additional transactions that are made feasible by the upgrade. Therefore assessing the value of a network upgrade requires identifying the set of additional transactions with the highest net surplus that can be supported as a result of the upgrade. However, the specific economic and institutional features of the gas industry require significant departures from the methodology developed for electricity.
The first specific feature of the gas industry is that most of the gas consumed in Europe is imported from non-European countries. Therefore, if the SOs and the regulators act on behalf of the European citizens, the welfare notion relevant for the assessment of the gas transmission upgrades should not include the producers’ profits. In practice that means that the cost-side of the welfare function should not reflect the gas production costs, but should reflect the gas procurement price assessed at the European borders.
The second feature is that long-haul transmission infrastructures are usually idiosyncratic to investments in gas production. The merchant regime appears the most suitable for that type of infrastructure, as investors need to control access to the transmission capacity to reap the benefits of their investment in production over the relevant time frame. We therefore expect the merchant model to feature prominently in the gas industry in the future.
The third feature specific to gas relates to the trading arrangements. The liberalization of the European gas markets has not yet delivered its full impact. That depends on various elements, including the fact that Third Party Access and the Use It Or Lose It (UIOLI) provisions on the existing international pipelines are not yet fully effective. In addition, wholesale spot gas (and transmission capacity) trading within Europe are still limited, because of contractual and/or regulatory frictions inherited from the past. Improvements to those areas of the regulatory framework may dramatically modify the assessment of the opportunity of some transmission upgrades. Therefore the value of additional transmission capacity cannot be assessed under the assumption that the regulatory framework, as we see it now, is stable.
Finally, forecasting the future transactions of gas in order to assess the market value of gas transmission upgrades is very difficult, given the lack of transparency and the nature of the transactions. Predicting the electricity production (and cost) at each location is – at least conceptually – relatively easy, once one has predicted the evolution of demand and of the installed generation capacity. On the contrary gas transactions, in particular at the production level, depend on many conditions – related to the global economic and political environment – whose prediction is a risky exercise.
For those reasons the methodology for assessing the value of gas transmission upgrades must be designed in a way that allows the Planner to extract the greatest possible amount of information from the market. We have therefore developed our proposal around a hybrid institutional setting, compatible with the Directive 73/09, in which the assessment of the value of the gas transmission upgrades is based on the availability of market investors to take on some of the corresponding risk.
In the proposed hybrid framework the SO operator acts as the aggressor of the market demands for additional transmission rights. In this framework market investors bear part of the investment risk, as they commit to purchasing the additional transmission rights over a given period of time.
That methodology appears to be flexible enough to address a wide range of investment opportunities, including investments that increase the system’s flexibility and investments that will mainly support so-called “transit flows”, provided an adequate degree of coordination among the SOs is reached. We also discuss how investments in excess capacity, motivated by security of supply concerns would fit into our proposed methodological approach. Finally we argue that one of the advantages of the proposed methodology is that it reduces the need for arbitrary common cost allocation exercises.
Accounting for security of supply in the gas sector
The European Regulation (994/2010) sets target levels of security that can be directly reflected in the assessment of the transmission upgrades. Members States are required to ensure that no service disruptions occur in the case that one major piece of infrastructure defaults. As far as supply standards are concerned, requirements are set to ensure the availability of supply of gas to protected customers under extreme demand conditions. Finally the Commission states in its Communication, COM(2010) 677/4, on energy infrastructures: “Every European region should implement infrastructure allowing physical access to at least two different sources”.
Once the security targets are defined, the SO will figure out the adverse events that might threaten security of supply, like for example a failure of the main transmission infrastructures, storages or LNG terminals, or interruption of supplies from a certain country. On that basis the SO can assess if the security criteria are met, i.e. if – given the infrastructure endowment – supply to the final customers is threatened by some of the adverse events.
In the case that the security constraints are not satisfied the SO will add to the network investment plan additional transmission capacity, in order to meet the security targets at the minimum cost.
Accounting for market power in the gas sector
It is generally recognized that an increase in the transmission capacity is likely to increase competition among suppliers. Still, one has to distinguish between transmission upgrades that are conditional on a long-term supply contract (contracted transmission capacity) and upgrades that do not necessarily bring new gas. Assessing the impact on competition of the first type of investments is relatively straightforward, as the standard competition policy toolbox can be deployed in order to analyze the importing country’s wholesale gas market. The impact of the additional gas imports on competition depends on the position of the importing firm that controls the incremental transmission capacity in the market and on the competitive interaction among the active wholesalers in the market. The effect of the entry of additional gas in an oligopolistic market is likely to be properly captured by (changes in) the usual concentration indices based on market shares.
For the second type of investment, instead, the assessment can be performed by measuring gas price differences amongst involved countries. If the wholesale price differences among the countries are large and steady, it is particularly important – for the purpose of predicting the competitive effects of the network upgrade – to understand why market investors are not ready to fund that investment on a merchant basis. The reasons as to why the investment is unattractive to market investors might also prevent the competition-enhancing effects of the transmission capacity increase to unfold, in case the investment took place in the “regulated” environment. For these reasons we suggest that investment decisions based on the expectation of a competition enhancing effect of the additional transmission capacity should be based on a thorough assessment of the market conditions.
New investments can bring about several external environmental effects. Whenever valuing any network upgrade it is thus important to attach a monetary value to those effects in order to assess their relative magnitude. Those effects can be produced directly by the new transmission facility (e.g. land use, electromagnetic pollution, reduction of visual amenities), or by the changes in the market stemming from the new infrastructure (e.g. increased renewable generation, reduction of losses).
We describe a methodology developed within an EC project, called ExternE, whose results are publicly available and are used by the European Commission (DG Environment) to value external costs. This methodology aims at attaching a monetary value to all external effects originating from energy related activities. In particular, ExternE permits to analyze four types of externalities:
- Geographically limited environmental externalities – the release of either substances or energy into the environmental media;
- Biodiversity loss;
- Climate change externalities – the release of GHG;
- Low probability –high damage risks.
Transmission investments, besides increasing welfare, may cause a large surplus redistribution amongst geographic areas and, within an area, between generators and consumers. The scope and direction of those wealth transfers depend on each market participant’s hedging position against electricity and gas price changes resulting from the network upgrades.
The first political question is whether some wealth-transfer effects of the investment should be sterilized through appropriate policy measures. Besides consideration of fairness, leaving the pre-investment surplus allocation unchanged, that would facilitate reaching consensus on the construction of positive-net-valued investments. This issue might be particularly relevant for investments whose effects are cross-border, in particular if in the exporting country the political weight of electricity price increases is higher than the political weight of increased profits obtained by the generators.
Although our discussion on how to split the cost of cross-border network upgrades is carried out with reference to the effects of the upgrades on electricity (or gas) prices in each country, our could be extended to benefits and costs that are not directly reflected in electricity (and gas) prices (indirect benefits).
We have identified at least two cases where public policies appear to reflect surplus redistribution concerns. First, the new electricity market design being discussed in France, which fixes the existing allocation of the nuclear rent between the generators and the French customers. Second, in the US, the Devers-Palo Verde No. 2 case appears to be an example of a net-positive valued investment rejected because of its (infra-marginal) surplus redistribution effects.
In the US the “beneficiary pays” principle seems well established, even though methodologies that do not link the cost allocation to any measure of the economic benefits gained by the different stakeholders are still extensively implemented. When the “beneficiary pays” principle is evoked, the cost of network upgrades are allocated to customers located in areas where, because of the upgrade, greater imports are expected to take place. This appears consistent with the view that, in the long term, the expansion of the generation capacity in the exporting areas will bring prices in the exporting countries back to the levels prevailing before the network expansion. Nevertheless, the fairness of that approach, could be questioned as the installed capacity adjustments might take a long time and massive welfare transfers would take place before the system settles to a new long-run equilibrium. The same line of reasoning appears to provide a foundation for a priority use of the congestion rents to pay for transmission upgrades.