13. The Economics of Energy Networks

In spite of their many differences and specificities, electricity and gas are two energy carriers unequivocally associated with the existence of large and complex transportation networks to move energy from production to consumption points. While long-distance transportation is common for other energy sources (see, for instance, the global seaborne coal trade) and networks to connect producers to consumers are not unusual (see, for instance, the extensive pipeline systems for crude oil and refined products), only electricity and gas display networks as a fundamental feature, without which they would be rendered almost worthless and unable to play a role in modern energy systems. Electricity and gas are network energies par excellence. For this reason, in this chapter we will simply refer to ‘energy networks’ to indicate the infrastructure to transport electricity and gas.

This chapter will provide an overview of the economics of transporting electricity and gas through networks. In Sect. 2, we will describe what energy networks are, with a focus on their physical and economic properties. In Sect. 3, we will discuss the monopolistic nature of energy networks and the implications for electricity and gas systems. In Sects. 4, 5 and 6, we will review how energy networks are treated in competitive energy markets, how access to networks functions and what arrangements are established to ensure efficient economic outcomes and equal treatment of all market participants. In Sect. 7, we will explain how access to energy networks is charged and how network users exchange energy within a network.

The movement of electricity and gas through networks are very different phenomena from a physical perspective.

Electricity networks are made up of electrical conductors (most commonly aluminium wires wrapped around a steel core) through which electrons flow as a result of a difference in electric potential between two points (called voltage), creating an electric current. Modern networks are based on alternating current (AC) with variable voltage oscillating with a frequency of 50 or 60 cycles per second (Hertz). Direct current (DC) elements are sometimes used to flow electricity between separate AC networks. Rectifiers are used to covert AC into DC and inverters are used to covert DC into AC. The amount of electricity a set of wires (referred to as a line) can transport over a given distance is a function of its thermal capacity (measured in Watts) and peak voltage (measured in Volts). Lines are usually placed above ground on steel towers, wood H-frames, wood or concrete single poles of differing structures and heights depending on their voltage and external environmental conditions. Lines can be buried underground and even submerged in water in areas where overhead lines are technically unfeasible or unacceptable for environmental reasons. The complex physics of electricity requires electricity networks to be equipped with numerous instruments and devices that control and regulate the system. Switching stations and sub-stations housing transformers are disseminated through the networks to ensure that the voltage of the current flowing through the lines is always appropriate. Circuit breakers are necessary so that flows can be rapidly disconnected from networks to avoid disruptions and equipment damage.

Gas networks consist of pipelines (usually buried underground), valves, compressor and metering stations. Pipelines can be made of carbon steel, high strength plastic or composite material depending on their diameter and the pressure level at which they are operated. Compressor stations (fired by turbines, electric motors or engines) pressurise the gas to reduce its volume and propel it through the pipelines by creating a pressure differential so that gas will flow from the high- to the low-pressure points in the network. They are installed at regular intervals of 50 to 160 km to ensure the right level of pressure and a constant flow rate are maintained. The speed at which gas moves within the network ranges from 15 to 32 km per hour. Valves work like gateways, blocking the flow of gas and directing it where required. Metering stations are used to monitor, manage and account for the gas flowing through the pipelines. They are often associated with other control components such as filters and odorisation equipment.

In spite of these key fundamental differences, electricity and gas networks are structured and classified in a similar manner. We conventionally divide energy networks into transmission and distribution networks. Transmission refers to the movement of electricity and gas over long distances, through high-voltage lines in electricity and large diameter high-pressure pipelines in gas. Distribution refers to the networks connecting transmission systems to end users through low-voltage lines and low-pressure pipelines. There is no conventional dividing line between transmission and distribution. In electricity, most distribution networks operate below 50 kV, but some are operated at up to 132 kV and some transmission lines are operated as low as 66 kV. Likewise, in gas, parts of transmission and distribution networks operate at similar pressure levels around 200 psi, but some transmission pipelines operate at above 1000 psi and pipelines connected to end users operate at below 10 psi. The connection points between transmission and distribution networks, however, are well identified and are usually called city gates. In both electricity and gas, some large consumers (such as industrial sites and gas-fired power stations) are able to connect directly to the transmission network, bypassing the distribution stage.

Energy networks have been planned to accommodate flows from a few dozens of large injection points (thermal or nuclear power plants, import pipelines, gathering pipelines connecting gas production fields) to a few dozens of large withdrawal points (distribution networks, large consumption sites) and most transmission lines and pipelines have operated on a one-way basis. However, the evolution of energy systems has increased the need to have energy networks that can accommodate bi-directional flows. In electricity, especially, the rapidly growing output from distributed renewable energy sources (DERs) connected to distribution grids is increasing the instances in which electricity flows from low-voltage to high-voltage lines. In gas, energy security and diversification objectives have prompted investment to enable some networks to operate more flexibly.

Networks are a complex and costly undertakings. Several estimates of the cost of gas pipelines and electric lines per kilometre or per unit of energy transported have been made but they are reliant on a huge number of assumptions that render these calculations of little general use. It is, however, possible to identify some key features about the cost of energy networks:

A remarkable consequence of the economic properties described above is the ability to generate a rare consensus within the economics profession—energy networks are unanimously considered natural monopolies. The concept of natural monopoly has been discussed in economics since the nineteenth century and is formally defined as a particular activity in which a firm can serve the market at a lower cost than any combination of two or more firms.¹ In essence, the economies of scale of energy networks are so large that, whatever the level of output, the long-run average cost of transporting electricity and gas is continuously decreasing (and is always above the long-run marginal cost). This creates a decisive prime mover advantage and an insurmountable barrier to entry for latecomers. Any attempts to introduce competition in natural monopolies would result in a wasteful duplication of assets and the failure of the new entrant, unless it is continuously subsidised. Competition in energy networks is therefore neither sustainable nor desirable (Fig. 13.1).

Some exceptions to this general principle are represented by relatively simple DC lines and long-haul pipelines in which multiple competing providers can serve the market profitably if demand is sufficiently high. These are commonly called merchant transmission investment. Successful examples are very rare in practice.² Many of the merchant transmission lines in Australia in the early 2000s and the IUK and BBL pipelines connecting the UK with mainland Europe have subsequently applied for regulated status following changes in market conditions and the expiration of the long-term contracts that initially triggered the investment.

The ownership of energy networks, if unchecked, provides exorbitant market power and gives rise to opportunities to foreclose markets to competitors and discriminate between firms engaging in activities for which network usage is necessary, such as gas production, electricity generation, gas and electricity supply. While economic theory has shown that long-term contracts can be used to govern the unequal relationship between network owners and network users,³ in practice, this enormous advantage has discouraged investment and market entry, resulting in the establishment of monopolistic market structures beyond transmission and distribution. Since the early days of energy networks, vertical integration along supply chains emerged as the dominant industry structure and the provision of electricity and gas rapidly became the prerogative of vertically integrated local or national monopolies (Fig. 13.2).

When acting purely on the basis of profit-maximising considerations, monopolists inevitably take advantage of their market power and hike prices to a level significantly above marginal cost. The impact of such a decision is particularly severe in the energy sector given the very low price elasticity of energy demand and the large spill-overs energy costs have on other economic sectors and society at large. Hence, public intervention is warranted and it can take the form of changes in ownership or regulation. While conceptually very different, the impact of the two models is very similar. In both cases, public authorities ensure that the monopolist no longer acts as a profit maximiser but sets its prices and makes key decisions taking broader welfare impacts into account.

Public ownership is the simplest and crudest measure that can be taken to avoid abuse of market power by a monopolist. It has been the preferred options for governments across the world for much of the twentieth century. Public ownership of energy assets, including but not limited to energy networks, has long been the norm, either as the result of acts of nationalisation (such as in France in 1946 or in the United Kingdom between 1947 and 1949) or due to the direct involvement of central or local governments in the establishment of these industries (as in the cases of Eni in the Italian gas sector or the stadtwerke, or municipal utilities, in Germany). A variant of public ownership is co-operative ownership, whereby network owners are fully or partially private actors but their interest is not profit maximisation from the natural monopoly activity. Cooperatives (such as agricultural or industrial consortia) were very common in the early days of the energy industry and are experiencing a revival with the proliferation of DERs and microgrids.

Regulation is an alternative model in which assets continue being owned by private firms but their pricing policies, revenue requirements, terms of service as well as any other key decisions around operations and investment are defined by public authorities through legislation and regulatory acts. A firm subject to this regime is called a regulated entity. In order to guarantee their technical competence and neutrality, the competence for rulemaking is usually allocated to a technocratic regulatory authority that is formally independent from government departments. This is the case, for example, of investor-owned utilities in the United States or the UK National Grid after its privatisation in 1990, whose activities are tightly monitored and regulated by the competent state public utilities commissions and the Office for the Gas and Electricity Markets (Ofgem) respectively. Most countries in the world have adopted this model in recent decades after a process of privatisation of state-owned assets, but there are cases of early adoption. The United States, for instance, regulated private inter-state transmission companies with the Federal Power Act of 1935 and the Natural Gas Act of 1938.

The choice between public ownership or regulation of private assets have often been determined by ideology, with nationalisations commonly implemented as part of a programme of sweeping economic reforms by left-leaning or socialist governments and more conservative administrations favouring regulation without impinging on existing property rights. The level of capability within public agencies also plays a role. Governments with limited know-how tend to favour public ownership due to its simplicity—once the nationalisation process is completed, they will have full control over decision-making processes in the industry. On the other hand, regulation of private assets requires constant monitoring and a deep understanding of industry functioning to ensure rules are always fit for purpose and keep pace with change.⁴ For these two reasons, the pendulum has decidedly swung from public ownership to regulation from the late 1980s to the 2000s as free-market doctrines imposed themselves as the mainstream ideology in economic policy and governments had built up more sophisticated expertise. Even in countries where government ownership was retained, vertically integrated firms were incorporated as limited companies and independent regulatory authorities were created to regulate and oversee them. More recently, with state intervention experiencing newfound intellectual popularity and decarbonisation policy objectives posing unprecedented challenges to energy systems, calls for public ownership have resurfaced.

Perceived shortcomings of vertically integrated firms, either government-owned or regulated, led to attempts by policymakers to introduce competition in the electricity and gas sectors. This process has conventionally been termed liberalisation, restructuring, reform or, with a misnomer, deregulation. A prerequisite for effective competition is the separation of the natural monopoly element from the other segments of the value chain where competition can exist. Such a vertical de-integration is termed unbundling and it consists of the creation of separate network companies that cannot engage in other activities along the electricity and gas value chain. These network companies continue to be regulated entities, whereas firms active in other segment of the value chain are left free to operate as profit-maximising entities. The rationale for unbundling is to avoid conflicts of interest and ensure that both operational and long-term strategic decisions regarding networks are taken in an independent and transparent manner treating all firms active in the sector in a non-discriminatory fashion. With no dominant player benefitting from the enormous advantage provided by the control over networks, firms could compete on an equal footing and, the theory goes, invest and provide consumers with better services and cheaper prices.

After unbundling, ownership and operation of networks usually coincide, even though there are cases in which the two functions are performed by separate entities. Unbundled firms are conventionally called Transmission System Operators (TSOs) or Distribution System Operators (DSOs) in Europe. The use of the term Distribution Network Operators (DNOs) is also common, especially in the United Kingdom. In the United States, gas TSOs are simply called pipeline companies, whereas in electricity we distinguish between Independent System Operators (ISOs), which are company that operate networks they do not own, and Regional Transmission Organizations (RTOs), which are multi-state network operators. In this chapter, we will use the generic term ‘network operator’ to indicate the companies operating an energy network, regardless of ownership arrangements.

Conceptually, four types of unbundling can be distinguished (Table 13.1):

The first country to pioneer unbundling was Chile in 1981,⁵ followed by the United Kingdom between 1986 (for gas) and 1989 (for electricity). Unbundling has subsequently been the cornerstone of the liberalisation of European energy markets promoted by the European Commission in the 1990s and 2000s. International financial institutions routinely include unbundling in their set of recommendations and make support conditional to its implementation. The separation of Ukrtransgaz from Naftogaz completed on 1 January 2020 in the Ukraine following pressure from the IMF, the European Bank for Reconstruction and Development (EBRD) and the European Commission is the most recent example. Some form of unbundling has now been implemented in most of Europe and Latin America but vertical integration still dominates in Africa, much of Asia as well as, somewhat surprisingly, North America.

Numerous studies have attempted to demonstrate the effectiveness of unbundling using econometric techniques, but evidence has been inconclusive, and often contradictory.⁶ In most of these studies, end user prices are used as the metric of success for unbundling with a very simple logic—if prices in the period following unbundling are lower than in the period preceding it, unbundling is considered successful; if prices are higher, it is a failure. In reality, too many intervening variables are at play, reducing the explanatory power of these analyses. First, low end user prices cannot be reliably used as a proxy for functioning markets as too many factors contribute to their formation. Electricity and gas prices are highly dependent on global commodity cycles, which in turn depend on industry specific and macroeconomic trends. Moreover, the period following unbundling have coincided, at least in Europe, with early attempts to decarbonise energy systems, which resulted in direct support for renewable energy sources and higher system costs, most of which have been passed on to end users. Second, unbundling in isolation cannot be used to define the success of market liberalisation. Even after the separation of networks from the rest of the value chain, one or a handful of dominant firms can still have tools to exercise market power, collude and restrict market entry. If this happens, additional policy measures are necessary, either through horizontal de-integration (breaking up large generation and supply companies) or direct support and facilitations for new entrants.

When these elements are taken into consideration, the debate over the effectiveness and benefits of unbundling blends into the broader debate about the effectiveness of liberalisation and competition in network energies.⁷ The separation of networks from the rest of the value chain is a necessary element for the creation of functioning competitive energy markets, but it is not sufficient alone. On the other hand, it is difficult to envisage competitive energy markets without some form of network unbundling.

As a result of unbundling, gas producers, electricity generators and suppliers have to become customers of transmission and distribution networks, or network users, to continue operating their businesses. Access to unbundled energy networks and all interactions between the networks and their users are governed by a set of detailed rules that ensures that all network users are treated equally. These rules, usually called network codes, are reviewed and approved (if not drafted) by regulatory authorities. This is the principle of regulated third-party access (rTPA).

Another key element governed by rTPA is the ability to dispatch energy to various points within the network. This is done through the reservation of the right to transport a defined amount of energy through a pipeline or a transmission line over a specified period of time. Reserved network capacity is called a transmission right in electricity, whereas in gas the phrase capacity booking is preferred. The two concepts, however, are not fundamentally different. rTPA rules ensure that all prequalified parties can reserve network capacity and become network users.

Network capacity is allocated in the form of standardised products allowing to transport a fixed amount of energy over a period of a year, a month, a day or an hour. Half-yearly and quarterly products are also allocated by some electricity networks. Multi-annual capacity bookings (up to 15 or 20 years ahead) were once common, especially in gas, but their use is now increasingly rare.

Network users book in advance the amount of capacity they need based on their estimated peak demand over the relevant period. If their capacity needs are predictable, they can try to profile their bookings through a combination of products of different durations (Fig. 13.3).

The process through which network users can obtain transmission rights or capacity bookings is termed capacity allocation. It can take several forms:

Capacity allocation can be either explicit or implicit. Explicit allocation is the most intuitive process, whereby the network operator first allocates the capacity, then requests the holder of the capacity booking to communicate the amount of energy it intends to flow through that capacity. Such a communication is called nomination, or scheduling. Explicit allocation is used almost universally in gas markets and is common in electricity markets for timeframes of one month or longer. On the other hand, when an implicit allocation mechanism is in place, network capacity is assigned automatically to the network users flowing energy between two network points. It is very rare in gas markets, while it is used to allocate capacity for timeframes of a day or shorter in most competitive electricity markets in Europe and North America. Day-ahead cross-network capacity within the EU is allocated through an implicit auction mechanism called flow-based market coupling whereby an algorithm determines the most efficient flows through the European networks given available capacity within the networks. Implicit auctioning is considered a more efficient allocation method as it ensures that capacity is allocated to the highest bidder and all allocated capacity is actually utilised by the network user.

An important feature of network capacity is their firmness. Firm capacity gives the user that books it a firm right to flow energy through it. However, this cannot be guaranteed in practice as flows of energy through the network are not always reliably predicted and network congestion may occur. In these situations, network operators can prevent holders of capacity from using it and block any scheduled flow of energy. Such an action by the network operator is called curtailment. The problem is obviously more acute in electricity given the greater complexity of managing flows for this energy carrier, but it is not uncommon in gas, especially in case of exceptional events such as unplanned maintenance or unseasonal cold snaps. Holders of firm capacity that is curtailed are entitled to receive compensation from the network operator. Rules around curtailments and compensations are amongst the most controversial aspects of rTPA regimes. A common practice in gas networks is to allocate interruptible capacity. Holders of this type of capacity do not have a firm right, so network operators can curtail their flows without compensation. Such capacity products are very rare in electricity.

Another important distinction between types of capacity products is the one between physical and financial transmission rights. Physical transmission rights (PTRs) give their holder the right to physically dispatch energy between two locations. On the other hand, financial transmission rights (FTR) are financial options that replicate the economic outcome of holding actual network capacity. In practice, a holder of an FTR between two locations will sell energy in one location, buy energy in the other location and receive the difference (spread) between the two market prices, if positive, from the network operator that allocated the FTR. While PTRs cannot guarantee full firmness for the reasons described in the previous paragraph, FTR are financially firm, meaning that the network operator is obliged to correspond the price spread under all circumstances, irrespective of whether the flow of energy was physically possible. The allocation of FTR is therefore very complex for network operators and requires a deep understanding of network flows and high computational abilities to allocate the right amount of FTRs at the right price. All capacity bookings in gas are PTRs. FTRs are common in electricity markets in North America and are gradually being introduced in Europe.

Allocation of network capacity in derogation to the principle of rTPA is exceptional but commonly foreseen for new infrastructure projects that would otherwise not be realised. The rationale behind TPA-exempted capacity allocation is that network users would not commit to the level of capacity bookings necessary to make the project viable unless they are granted the privilege of exclusive access to the new infrastructure. TPA exemptions are usually approved by regulatory authorities with strict conditions attached and for a limited period of time (Fig. 13.4).

As regulated monopolies, energy networks are subject to stringent revenue regulation. The basic principle of revenue regulation is that the remuneration that can be accrued by a network operator (usually called allowed revenue) is constrained by rules and parameters set by the regulatory authority. In order to provide stability to both network operators and network users, allowed revenues are set and held stable for a period of several years (usually five), which is called regulatory period. Significant changes can only take place between different regulatory periods. Revenue regulation is arguably the most crucial and complex task energy regulatory authorities have to perform in a liberalised market.

No two revenue regulation regimes are alike, but the methodologies used by regulatory authorities can be classified into two broad families: rate-of-return (also called cost-of-service) regulation and incentive regulation, in which we distinguish between price-cap regulation and revenue-cap regulation. In a rate-of-return regulation regime, the regulatory authority sets a target rate of return the network operator is entitled to receive on the capital invested. The revenue of the network R will be equal to:where:

The crucial variable in the formula above is r, which must be set at a level that is sufficient to attract the necessary level of investment. In accounting terms, it is said that r must be above the network’s weighted average cost of capital (WACC), that is the firm’s cost of servicing its debt and making its equity investable.⁸ Rate-of-return regulation is effectively a form of cost-plus pricing, as the network operator is guaranteed a fixed margin (in this case a fixed percentage of the RAB), irrespective of the level of its costs. Whilst this system guarantees stable long-term returns to investors, which in turn tends to lower financing costs, it provides the network operator with no incentive to reduce its operating expenses. Moreover, given that the remuneration is directly proportional to the level of the RAB, it incentivises networks to over-invest in capital assets, a phenomenon that is pejoratively referred to as gold-plating. In spite of these shortcomings, rate-of-return regulation has been the standard methodology to regulate monopolies in the energy sector for most of the twentieth century and its use to regulate energy networks is still widespread, especially in the United States.

Price-cap regulation was developed in the United Kingdom in the 1980s in response to the above-mentioned inefficiencies of rate-of-return regulation. Its origin is conventionally traced back to a 1983 report for the UK Department of Industry on the recently privatised telecommunication industry.⁹ As the name suggests, this methodology is aimed at directly capping the prices the network operator can charge, by limiting the increase Δ P by the following formula:where:

The objective of price-cap regulation (often simply referred to as ‘RPI minus X’) is to incentivise the network operator to operate more efficiently by letting the firm keep the additional revenue generated in case the efficiency gains it achieves are greater than the parameter X. The implicit assumption behind this idea is that, due to information asymmetries, the regulatory authority is unlikely to correctly assess the value of the network’s asset base and its operating costs (which are key parameters in determining the network’s remuneration in a rate-of-return regime). By adopting price-cap regulation, one could expect that the network operator’s full efficiency capabilities would be revealed and the regulatory authority could eventually set regulated prices at a lower level by adjusting the parameter X in the following regulatory periods. Due to its theoretical attractiveness and simplicity, the uptake of price-cap regulation across the world was rapid. Price-cap regulation proved particularly popular in Latin America and Asia during the privatisation wave of the 1990s and early 2000s. However, empirical evidence of the superiority of price-cap regulation is limited and the extra-profits it allows network operators to retain have frequently triggered political backlashes. Even in the United Kingdom, the pure RPI minus X system was rapidly abandoned in favour of hybrid regimes that monitored the behaviour of network operators more intrusively.

Revenue-cap regulation shares many of the elements of a price-cap regime, with the exception that, as the name suggests, the variable on which a cap is imposed is the total revenue the network operator is entitled to earn. In a stylised representation, the revenue R₁ a network operator can accrue over a period is equal to:where:

While conceptually very similar to price-cap regulation, one crucial feature of revenue-cap regulation is that it decouples the network’s revenue from the amount of services sold.¹⁰ As such, this regime insulates network operators from demand fluctuation, making it particularly apt for activities whose costs are overwhelmingly fixed and in which public policy objectives often favour lower network utilisation (see, for instance, the promotion of energy efficiency, self-consumption and demand response). The majority of networks in Europe are currently subject to some form of revenue-cap regulation.

As much as accumulation of experience and improvements in computational ability will continue refining the capabilities of regulatory authorities, revenue regulation is deemed to remain an area prone to errors and controversy. On the one hand, network operators tend to have better insight than the regulatory authority over some of the key parameters and may be tempted to game the process. On the other hand, the inherent uncertainty of other input factors does not depend on information asymmetries. For instance, neither the network operator nor the regulatory authority is able to forecast with precision demand trends and interest rates, which significantly affect network utilisation and the viability of investment. Under these circumstances, the accuracy of revenue and cost forecasts for several years ahead is inevitably low, prompting the occurrence of situations in which the network gets either overcompensated, thus undermining the credibility of the regulatory authority, or gets undercompensated, resulting in harmful under-investment or even endangering the financial viability of the network operator.

In accordance to the principles of revenue regulation and rTPA discussed in the previous sections, the fee a network operator can charge network users for each service it provides (such as a network connection or the booking of capacity at a network point) must be set at an equal level for all network users, called regulated network tariffs. In case a service is allocated through an auction, the regulated tariff will be the auction starting price. The calculation or approval of network tariffs, which result from the application of a predefined methodology (also called charging regime), is another key task of energy regulatory authorities. Tariffs are a politically sensitive topic as they determine the allocation of network costs among different categories of network users, which in turn significantly influences the energy costs paid by different end users.

Like revenue regulation regimes, network tariffs methodologies vary greatly from one to another. The main distinction that can be observed is between zonal and nodal tariff systems. In a zonal tariff system, network users pay fees to the network operator when they book capacity to enter and exit the network, while they are not charged for moving energy within it. For this reason, they are also called entry-exit systems. From a practical perspective, a network user injecting energy at network point A and withdrawing it at network point B will book entry capacity at point A and exit capacity at point B, pay the corresponding tariffs, then schedule energy flows at these two points. The movement of energy between point A and point B is solely managed by the network operator. Zonal tariff systems are divided into postage-stamp regimes and methodologies that take into account locational signals. In the former, like in traditional postal systems, tariffs at all entry and exit points are the same regardless of the costs incurred to move the electrons or gas molecules between network points. In the latter, such costs (which are usually driven by the distance between points) are taken into account when determining the tariffs. The majority of electricity transmission networks and the near totality of gas transmission networks apply a zonal tariff system. Distribution networks, both in electricity and gas, usually charge according to a zonal postage-stamp system.

A nodal tariff system is a more complex regime in which network operators charge users a tariff for each movement of energy between two nodes of the network. Such a granular charging of network capacity can potentially lead to the emergence of a different price for energy at each point of the network. For this reason, these systems are also called locational marginal pricing (LMP) systems. In practice, in a nodal tariff system capacity between any two network nodes is usually auctioned with a reserve price of zero, so there will be a positive price for capacity between two nodes only if there is more demand than capacity available, or network congestion. The difference of price between two locations is therefore called congestion revenue. There is a broad academic consensus on the benefits of nodal systems over zonal ones because they allow for more efficient pricing of energy within networks and, consequently, more efficient network utilisation.¹¹ However, zonal systems are still more common as they are generally simpler to operate and less politically controversial.¹² Nodal tariffs have been adopted in several electricity transmission networks in the United States over the 1990s and 2000s, but their uptake outside North America has been slow.

Network tariff methodologies also influence how network users exchange energy between themselves. In zonal tariff systems, it is common for the network operator to manage virtual trading points (also called virtual hubs), either directly or through an appointed third-party provider, at which transactions notionally take place. The alternative for network users would be to trade at the interconnection between two networks (called flange trading). Across Europe, for instance, all networks (or cluster of networks) have their own virtual trading point, which tends to be given a specific name in gas (for instance, TTF, NBP, NCG, PSV), while is simply called with the name of the network in electricity. Flange trading has been actively discouraged by policymakers since the early 2000s and has almost disappeared. In nodal systems, on the other hand, market participants can in theory buy and sell energy at each node of the network. In practice, trading coalesces at some key locations, or physical hubs, either because they are key infrastructural interconnections or because trading activity has conventionally focused there over time. In the United States, most exchanges of electricity take place at approximately ten major physical hubs. Likewise, the North American gas market is based on trading at Henry Hub (a physical location in Louisiana) and several satellite regional hubs.

This chapter has provided an overview of the structure and functioning of energy networks. Many of the key concepts outlined, such as unbundling, rTPA and revenue regulation, are currently at the core of the energy policy debate. Established wisdom in the field of the economics of energy networks is being revisited by academics and practitioners in the attempt to devise appropriate solutions and organisational models for the unprecedented policy and environmental challenges energy networks need to tackle. Current trends only superficially appear to be impacting electricity and gas networks in different manners. Instead, both share a future where rapid transformation and massive investment are necessary. Electricity networks are expected to cope with large increases in throughput due to the electrification of many energy uses (primarily road transport), while being able to manage more volatile and unpredictable energy flows resulting from the replacement of dispatchable thermal generators with non-dispatchable renewable installations. On the other hand, the gradual phase-out of fossil gas in power generation, industry and heating puts gas networks at risk of demise unless they promote a conversion of their infrastructure to low-carbon gases, such as biomethane and hydrogen. Closer interaction between electricity and gas networks (including joint infrastructure planning and operation) is also likely to take place.¹³

In spite of a much-publicised push to off-grid solutions made possible by rapid improvements in DERs and digitalisation, it is difficult to envisage a future in which networks do not continue to play a fundamental role in modern energy systems. Even in the plans of the most enthusiastic proponents of self-generation, continued reliance on network connection, either to supply energy or to evacuate excess on-site production, remains essential. Energy networks are therefore likely to be going through a rapid but incremental evolution of their role and functioning, rather than a full-blown revolution. Despite the radical uncertainty crippling the energy sector, we can confidently state that energy networks are here to stay.