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How must energy pricing evolve in a low-carbon future?


20 Sep 2018


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Dr John Rhys discusses redefining how we take our electricity supplies, the complexities of allocating fixed costs, and the need to recognise environmental costs through carbon pricing.

It is hard to understate the importance of retail tariffs for the efficient financing and operation of public utilities, and especially in the power sector. Tariffs (see note at the end of this article) represent the pricing and charging structure through which most consumers are supplied. They influence how consumers use electricity. Tariffs revenues underpin the returns necessary to pay for utility investment.

To meet objectives of both equity and economic efficiency, it is generally accepted that prices should accurately reflect costs.  This provides a means to coordinate consumer choices, on how much and how they use power, with utility decisions on how they manage, operate and invest in their networks and in their sources of generation. Purchase, as opposed to sales, tariffs set the terms on which small scale producers can sell into the network and are an important influence on the development of decentralised power production in particular.  However, interpretation of how best to reflect costs is, as we shall discover, quite complex and requires careful analysis and judgement.

In the new world of low carbon energy, three important trends will change the way in which electricity is produced and delivered, the shape of future tariffs, and the nature of the service relationship between utilities and households (and business). These trends are Decarbonisation, Decentralisation and Digitalisation (the three D’s), and they impact on tariffs.

Decarbonisation of the energy sector is widely perceived as requiring much greater use of non-fossil electricity to substitute for current fuels in heating and transport. But it also changes the cost structure and operational characteristics of generation technology. It substantially reduces the importance of variable (fuel) costs, which are what largely underpin the design and operation of today’s markets, and raises the importance of capital costs. Low carbon technologies (both nuclear and renewables) are inherently less flexible in adjusting to fluctuations in consumer demand. This raises the importance of managing consumption patterns, and hence of tariffs and price signals, within a coordinating price mechanism for balancing supply and demand in real time.

Decentralisation is implied by the growing significance of small scale producers (also sometimes known as prosumers), by the smaller scale of many renewable technologies, and the increasing importance attaching to management of local network constraints, as electricity plays a large and increasing role in overall decarbonisation strategies. Tariffs, especially those on which small consumers can sell to a public network, should be designed to make an efficient connection between small operators and larger local or national grids.

Finally, digital technologies permit much more complex and sophisticated information and control systems. These can help maintain stable and balanced power systems, enable more sophisticated tariffs and consumer choices, and permit more efficient management of consumer requirements. They are therefore part of the solution.

An Oxford Martin School team has recently reviewed some of the many questions surrounding retail tariffs, and we believe that there are some important general principles that should govern development of retail tariffs and retail supply in a low carbon future. The actual institutional arrangements governing the sector, in all countries, are usually very diverse mixtures of regulation and competition that are constantly evolving. Our proposals are intended to provide a new paradigm within which sector policies can evolve, and possibly a benchmark against which a successful approach should be judged.  

The Long Run Marginal Cost (LRMC) Approach

It is widely understood that for both renewable energy (and nuclear power) the marginal cost of generation, defined as the cost of an additional unit of production from existing generation assets, production or from low carbon technologies is close to zero. Setting retail prices at this zero short run marginal cost (SRMC) is clearly not a viable basis for pricing, and making the consumer’s marginal electricity consumption free at the point of use has the potential to create an unlimited demand that cannot be satisfied.

There is however another well-established cost reflective benchmark for approaches to electricity tariffs based on long run marginal cost (LRMC) principles. This is intended to ensure that consumers pay the full incremental costs (at least of generation), including capital costs, that they impose on the power system. A rigorous definition was provided by the distinguished electricity economist Ralph Turvey: “Marginal cost (as LRMC) is an engineering estimate of the effect upon the future time stream of outlays of a postulated change in the future time stream of output.”

This implies that the real costs of meeting very different types of load will be very different. High load factor (eg continuous or baseload) loads or those that are well matched to patterns of production will require lower capacity requirements per unit of energy supplied. Low load factor loads, or loads concentrated in winter if generation is cheaper in summer (eg with solar power), will be more expensive. This makes the calculation of LRMC, and hence what different kinds of consumption might pay, subject to careful analysis and calculation. To quote Turvey again: “There are as many marginal costs as there are conceivable postulated changes.” 

The importance of digital technologies is that they allow us to think about this kind of cost reflectivity in a much more granular way, and reflect the very different costs implied by different kinds of consumption such as the traditional household applications, electricity for heat pumps, or the charging of electric vehicles. Each of these can have a very distinct load profile, with a very different servicing requirement for the consumer.

Reliability requirements, the differentiated nature of consumer needs, and supplier managed load

The importance of capacity costs also brings into sharp relief the fact that the standard of supply reliability is itself a very important driver of costs. A high standard of reliability, defined as a very low probability of failure to meet the maximum, unconstrained, instantaneous, aggregate demand of all consumers, implies a need for very substantial spare capacity margins. These may be needed to cater for daily and seasonal peak loads, for generator downtime (eg breakdowns) and for weather related fluctuations in renewables output.

However not all consumption requirements need the same level of instant access and reliability. We quite reasonably expect our power need for lighting, or for a television programme, to be met instantaneously. We are likely to have a very different approach to, for example, overnight charging of an electric vehicle battery with perhaps 50 kWh of energy, and be largely indifferent to when it is delivered, eg overnight or even over two or more days. It makes sense to permit the supplier to choose the timing of delivery, within clearly defined parameters, in order to match generation availability and any network constraints. Other loads, such as laundry, or domestic water heating, will also have their own requirements, which the consumer can choose, in relaxing the requirement for instantaneous delivery of power.

What we expect to see in a low carbon future, therefore, is consumers being able to make a selection from a menu of tariffs, with different supply arrangements and prices in each case:

  • Some supplies, eg for lighting circuits, taken at a premium price, with the highest level of guaranteed reliability.
  • Some consumers choosing a lower reliability standard, at least for some of their needs, with a lower price.
  • Some large loads, such as vehicle battery charging or heating, provided on the basis that the supplier manages the timing of energy delivery.

Future systems will place a high premium on pro-active and effective management, based on innovative tariffs and a redefined approach to retail supply, of the use of electricity for electric vehicle charging and domestic heating applications.

Allocation of fixed costs

Generation costs are however only a part of the story. A substantial proportion of total power sector costs reside in high voltage transmission, and even more in the local distribution networks. As with many networks (including road and rail) the marginal cost of accommodating extra throughput (the extra car or train) is, at least in uncongested networks, very low. But the fixed cost still needs to be recovered. How best to do it poses some very difficult questions in terms of reconciling considerations of equity and income distribution, on the one hand, and the efficient allocation of economic resources on the other.

Current UK practice for smaller retail consumers, for example, is simply to average most fixed costs over all units of energy sold. This seems fair, and prima facie results in those who consume most (and might broadly also be those with higher incomes) paying the most towards the fixed costs. However this distorts the economic message, that the actual marginal cost is much lower. When policies for a low carbon economy include persuading consumers to use large amounts of extra  electricity for heating (eg with heat pumps), this becomes a very serious obstacle. For a household consumer, a higher fixed charge in the tariff, and a lower unit energy charge, transforms the choice between using the low carbon solution (electric heat pumps) and traditional fossil fuels (gas or oil). 

Another problem arises with purchase tariffs. These provide an incentive to small scale producers that should, in ideal world, result in consumers installing their own generation when this is “efficient” and results in a reduction in total societal costs. However, if the kWh rate in the purchase tariff is overstated by including an allocation of fixed cost, it will result in too much own generation. There will be no saving in fixed cost and, while the individual consumer with own generation may benefit, a larger share of fixed network costs will be picked up by others.

There are potential answers to this question that not argued in detail here, since they take us deeper into complex policy, political and administrative questions than is appropriate for a short article. Possibilities include the recovery of fixed  costs through property taxes, and approaches in which fixed costs are recovered with differentiation according to the use to which power is put, for example with a higher fixed cost levy on EV charging (a premium use of electricity) than for heating which is in competition with gas.  

Reflecting the substantial environmental and climate costs of CO2 emissions

In the transition to a low carbon economy the case for more realistic levels of carbon taxation, as an incentive to invest in low carbon generation assets, and to minimise the share of fossil fuel in both consumption and production, is overwhelming. However this is not current policy in many countries. The UK currently has a particularly perverse approach in that the burden of renewables innovation policy is loaded on to electricity but not on to other fuels, notably gas. A major plank of low carbon policy is to encourage the use of electricity for heating, through the medium of heat pumps, and to substitute for gas. But the impact of current policies imposes a discriminatory tax on electricity, raising prices and reducing any incentive for consumers to switch from gas. A well constructed carbon tax, by contrast, would increase the cost of gas, restore a level playing field, and tilt the balance of running cost comparisons towards the electric technology of heat pumps. Perversely, recovering the cost of innovation support through the power sector hampers progress towards a low carbon economy.

  • John Rhys is the author of a new study - Cost Reflective Pricing in Energy Networks - carried out with the Energy Systems Catapult, one of a network of world-leading centres designed to transform the UK’s capability for innovation in specific areas and help drive future economic growth, set up by Innovate UK, the UK's innovation agency.

Note: What we usually mean by a tariff is a set of prices that are published in advance, are open to all buyers (or for purchase tariffs, sellers) complying with a given set of conditions. They contrast with bilateral trading arrangements, and with “market” structures involving multiple buyers and sellers. They provide the standard route through which most consumers, and certainly smaller consumers, obtain their supplies of energy, water, and many communications services. It is quite normal for a supplier to offer a number of alternative tariff structures, between which consumers can choose an option that most closely reflects their needs. They can follow either simple one-part or two-part formats, or have more complex structures.

 


This opinion piece reflects the views of the author, and does not necessarily reflect the position of the Oxford Martin School or the University of Oxford. Any errors or omissions are those of the author.