The impact of PVs and EVs on domestic electricity network charges: A case study from Great Britain

Highlights

• In Great Britain, domestic distribution network charges will be Electric Vehicle (EV) dominated.

• For every 5% increase in EV uptake, the distribution charge decreases by around 2%.

• For every 5% increase in PV uptake, the distribution charge increases by around 1%.

Abstract

Electric power distribution network charges have become a popular area of study for regulators, industry and academia. Increasing use of photovoltaics (PVs) and electric vehicles (EVs) by domestic customers has created concerns about the fairness of the current tariff structure. Proposing a tariff design, which will be cost reflective, transparent, sustainable, economically efficient is socially desirable. Wealth transfer through electricity distribution tariffs is a major concern for energy regulators. This paper aims to analyse the current distribution network tariffs faced by four main household customer groups in Great Britain (GB) - defined as those who own a PV and an EV, those with EV but no PV, those with PV but no EV and finally those with neither EV nor PV – under various uptake scenarios for EVs and PVs. We illustrate the impact on household tariffs for the most and least expensive GB network operators, namely London Power Networks and Scottish Hydro Electric Power Distribution. The results show that, due to the current network charges calculation structure, as PV penetration increases, the distribution tariffs increase for all customers regardless of whether someone owns a PV or not. On the other hand, as EV penetration increases, the distribution tariffs decrease for all customer groups. Another key finding is that the distribution tariffs in Great Britain are EV dominated and the future EV and PV penetration projections indicate that the distribution tariffs will likely decrease for all customers in Great Britain.

Introduction

Electricity regulators, such as Ofgem in Great Britain, allow their distribution network operators (DNOs) to collect a certain amount of revenue during each regulatory control period. This so-called allowed revenue is calculated with reference to expected operating expenditures (OPEX), depreciation, interest and other costs of the network operators. The tariffs of each DNO are then determined and designed to recover these costs. However, the way to recover this given amount of revenue is a complex problem which is attracting the attention of DNOs, regulatory bodies and academia. Alongside this there is an increase in distributed generation (including domestic solar PV), storage units and electric vehicles (EVs) on the power grid. This has the potential both to reallocate who pays for the distribution network and to substantially increase distribution network cost. On the other hand, according to the Energy and Climate Change Public Attitude Tracker, Wave 23 report (BEIS, 2017) 20% of the British energy customers were either very or fairly worried about paying energy bills in 2017. The worry is highest among customers with household incomes up to £15,999 (26% of the customers) and lowest among those with household incomes over £50,000 (12% of the customers). It is against this background that the impacts of distribution charging methodologies under different PV and EV roll-out scenarios is of concern to regulators.

There have been several recent studies aiming to forecast the necessary amount of investment to meet the new challenges posed by the evolving power grid and changing consumer behaviour. The MIT Utility of the Future report (MIT Energy Initiative, 2016) observes that if the distributed PV generation increases to more than 20% of total electricity demand, then the cost of the network could double in the most extreme case. Similarly, a study by the Smart Grid Forum from Great Britain estimates that from 2012 to 2050, the network related investments would be as much as £60bn across all distribution and transmission networks in the country (Smart Grids Forum, 2012). During the decentralized energy transition, energy storage could be a game changer. With rapidly increasing distributed generation (DG) connected to the grid, intermittency arises as one of the major problems for the power system planners. In addition to the solutions proposed as a part of demand side management techniques, storage could be a viable option especially for domestic loads. Contemporary residential energy storage solutions can be summarized as follows:

• Power to heat, such as heat pumps

• Using electric vehicles as home storage, Vehicle-to-Grid (V2G)

• Batteries

Thanks to the rapid development of electric vehicles (and other sources of battery demand), the cost of batteries has been falling significantly. Average battery pack prices fell from US$1000 per kWh in 2010, to US$ 350 per kWh in 2017 (World Energy Council, 2017). It is evident that energy storage could therefore have a significant impact on distribution network costs by directly affecting the volume of energy imports and imports across the day in the presence of time-of-use (ToU) tariffs. Nevertheless, to narrow our focus, this topic has been omitted from the scope of this paper.

To achieve more cost reflective and more efficient network tariffs, different charging methodologies have been suggested by various researchers. A recent study from the United States focuses on distribution system cost analysis in the United States and concludes that if volume (kWh) decreases, the delivery costs are likely to increase in the future (Fares and King, 2017). Hinz et al. (2018) show that the grid charges in Germany are rising with the increasing penetration of distributed generation. The paper by Nijhuisa et al. (2017) analyses the cost reflectivity of different tariffs in the presence of changing EV and PV penetrations for the residential customers. Neuteleers et al. introduce alternative tariff schemes for electricity grids for Dutch households by evaluating them with respect to their fairness (Neuteleers et al., 2017). Passey et al. (2017) present a cost-reflectivity analysis of demand charge tariffs, which was done by using the energy consumption data of household customers in Sydney, Australia. Another study from Australia proposes five different tariff designs for distribution network charges to recover residual costs (Brown et al., 2015). However, this study does not designate a best solution for recovering these costs. Rubin (2015) suggests that seasonal residential electric distribution rates with seasonal consumption charges might be used to reach a more efficient rate design. On the other hand, a study from Sweden by Bartusch et al. (2011) proposes a demand-based tariff for residential customers instead of tariffs depending on average system costs, which in general, are not being differentiated by time-of-use. Other studies focusing on how distributed generation affect power delivery costs can be found (Cohen et al., 2016, Perez-Arriaga, 2016, Picciariello et al., 2015a, Picciariello et al., 2015b, Abeygunawardana et al., 2015, Georgilakis and Hatziargyriou, 2013, Yilmaz and Krein, 2013).

In a study from the United States, the implications of increasing PV penetration on network tariffs are studied by Picciariello et al., 2015a, Picciariello et al., 2015b. This study concludes that cross-subsidies arise when net metering combined with pure volumetric tariffs is applied. The amount of cross-subsidies varies depending on the amount of the distributed generation (DG) connected to the grid. In a study from California, US, Borenstein (2016) highlights the advantages and disadvantages of fixed and volumetric charges in recovering the fixed costs of the utilities and recommends an increased amount of fixed charges with time-varying volumetric rates. Another study by Eid et al. (2014) focuses on cross-subsidies due to net metering with increasing PV use and shows that if total PV penetration reaches 20% of the end-users, the cross-subsidies might reach as much as 7.8% of the tariffs. In his comprehensive study, Simshauser (2016) shows that for Queensland in Australia, the existing two-part tariff structure ends up in wealth transfer from the customers who do not possess solar power to the ones who do. The study concludes that the households that do not possess an air-conditioner or a solar PV faced a network charge increase at an amount of 295 AUD per year (Simshauser, 2016). Even though there are numerous papers addressing the impacts of PV uptake on distribution network charges, the literature for EV penetration and its outcomes on distribution charges and tariffs is quite limited.

This paper uses a case study from Great Britain which shows the impact of increasing penetration of photovoltaics (PVs) and electric vehicles (EVs) under existing network charges. Its aim is to show the extent to which different types of customers will see their charges vary under different roll-out scenarios for PVs and EVs, regardless of the underlying cost increases in network costs that such roll-outs might impose. This is an area which is of active concern to electricity regulators, one of whose primary functions is to protect consumers facing monopoly distribution charges. In Great Britain, the electricity regulator (Ofgem) has been working on a distribution tariff review to reconsider the ‘residual’ charges with the following core principles (Ofgem, 2017a):

• being cost reflective

• reducing distortions

• fairness

• proportionality

In addition to the main principles of Ofgem, the European Commission (EC) has its own guidelines for a better distribution tariffs design, where cost reflectivity is explained as where “costs should be allocated to those agents who impose the costs” (European Commission, 2016, p.35).

At this point, however, we should make a remark that the principle of cost reflectivity in Britain and in Europe is slightly different. By creating cost reflective distribution tariffs Ofgem aims to reflect the full economic costs in the network in ways that give incentives to customers to use the network efficiently. On the other hand, cost reflectivity from the European perspective is more about fairness. Distribution costs are supposed to be charged to those who are responsible for it. However, we see that fair tariffs are the common core concern for both Britain and Europe.²

In this paper, our main motivation is to question fairness in distribution tariffs in Britain. For a general discussion of the principles of network charging, see Pollitt (2018). As the problem statement, we ask; what is the situation with British electricity customers in terms of designing fair distribution tariffs among different types of customers who may or may not own EVs and/or PVs? To analyse this problem we examine two DNOs: the most and least expensive ones in Great Britain. For each, we define four customer types, which are:

• Customers who own PVs and EVs;

• Customers who own PVs but not EVs;

• Customers who own EVs but not PVs;

• And finally, customers who do not own either.

Section 2 of this paper gives brief information about the power distribution system, network charging and solar PV and EV potential in Britain. Section 3 presents the methodology and Section 4 includes the results of the tariff calculations per each customer group with respect to changing PV and EV uptakes. Section 5 concludes our paper with a discussion of the policy implications of our findings.