Alternative tariff structures

The Council of european energy regulators (Ceer) reinforces the thesis just presented and states that the change in technological paradigm, which transforms how distribution networks are used, exposes the need of redesigning network tariffs struc- ture, ensuring a tariff structure appropriated to this new context and its intrinsic challenges (Ceer, 2017).

tariff structures alternative to traditional, predominantly volumetric, charges are under review or have already started to be implemented in many countries. basically, these new rate designs aim to ensure that dG consumers pay their fair share of grid costs. as stated by bird et al. (2013), the network tariff structure goal can be to avoid systematic unfairness in the way tariffs assess grid costs to different consumers’ classes.

returning to the fact that traditional volumetric rates to recover fixed and variable costs becomes unsuitable in the case of FVdG, thus the redesign of network tariffs to better reflect cost-causation principles, is an important step in enabling a fairly appor- tion of the costs and benefits for a typical FVdG system (bird et al., 2016;

Costello, 2015).

as identified by the Ceer (2017), the overall objectives of network tariffs is to recover costs of building, operating and maintaining networks while incentivizing ef- ficient use and development. Historically, regulators have relied upon three key prin- ciples, which should be reflected in network tariffs (bird et al., 2013):

i. ensure the utility viability by yielding the total revenue requirement;

ii. Fairly apportion the utility’s cost among consumers;

iii. relatively stable rates without unduly discriminating against any customer or group of customers.

Considering the new paradigm, however, some additional assumptions must be considered when defining distribution charges’ structure, such as (Ceer, 2017):

i. Network tariffs should, as far as possible, be future-proof;

ii. tariff structures should be sensitive to the different costs of network provision;

iii. Net metering on self-generation that prevents the fair contribution of self-generation towards network costs should be avoided;

iv. all tariff structures reflect multiple objectives which need to be balanced;

v. regulators should have sufficient expertise.

in this sense, an increasing number of authors have been discussing the distribu- tion tariff structure most suitable to this new scenario, characterized by the growing participation of photovoltaic distributed generation in the grid. some alternatives con- sidered are (HleidiK aNd GreeNsteiN, 2016; siMsHauser, 2016; broWN et al., 2015; boresteiN, 2016; barbose et al., 2015; Costello, 2015):

i. Capacity-based charges;

ii. Fixed charges;

iii. Hybrid approaches, combining fixed charges and time-varying volumetric charges, for example.

each of these alternatives, and also their advantages and disadvantages, are going to be discussed below.

3.1.1. Fixed charges

Fixed charges are pointed out as simple stable and predictable both to distribution companies and consumers (Ceer, 2017). The rationale behind the adoption of this kind of tariff structure is that most of the distribution costs are fixed in the short run.

typically, an increase in a fixed charge for all household consumers is accompanied by a corresponding reduction in the energy charge, such that total utility revenues maintain revenue neutrality (bird et al., 2015). although higher fixed charges are a straightfor- ward and guaranteed mechanism to recover utility fixed costs (Kennerly 2014), they are quite controversial because of their possible negative impacts on low-income customers and on energy efficiency and self-generation adoption (bird et al., 2015).

Currently, in many countries and us states household consumers pay a fixed charge on their electric bill. in most cases, however, these charges are not oriented toward recovering grid costs, effectively. in the us states, for example, this monthly consumer charge is usually used to recover customer and facilities charges, such as call center and billing, despite of distribution infrastructure costs. Considering the costs they are supposed to cover, these charges are usually low, varying from $10 to $20, average (urbd, 2015).

Thus, the proposal of stablishing fixed tariffs for the recovery of grid costs represents quite a great difference in relation to what have been made until now, as it

requires completely, or partially, moving these fixed costs from the volumetric rates to the fixed charge.

The negative factors associated to fixed distribution tariffs are the possible increase of bills for lower energy consumers and the fact that they do not give signals in rela- tion to long term costs, nor encourage energy efficiency and system flexibility (Ceer, 2017). This kind of disincentive to energy efficiency associated to a shift to higher fixed charges and lower volumetric charges is due to the fact that consumers’ ability to reduce costs by increasing their efficiency would be reduced (bird et al., 2013).

brown et al. (2015) reviews the electric industry practice and the relevant price literature and identify that recovering significant costs in a fixed charge is perceived to be unfair of inequitable. This perception is related to the fact that consumers who do not have a high consumption level will have higher bills under such a system, and customers who consume a lot of electricity will have lower bills than under an alterna- tive arrangement where residual costs are recovered through volumetric charges. How- ever, the authors point out that the increasing participation of pVdG, while exposing the inefficiencies associated with recovering residual costs in kWh charges, “may also weaken the argument about the ‘‘fairness’’ of charging high, albeit cost-based, fixed charges” (broWN et al., 2015, p. 141). This happens because the increasing viabil- ity of installing rooftop pV systems is changing electricity price elasticity in a way that an increase in the volumetric charge that is sufficient to induce additional customers to install solar pV results in a large drop in those customers’ consumption of electricity supplied by the distribution network, may mean that the inefficiencies associated with volumetric tariff structures are greater now than they have been in the past.

brown et al. (2015) states that the option for recovering sunk costs through fixed charges, besides being considered unfair in comparison to current tariffs, is aligned with the strategy of prioritizing the principle of efficient prices.

another relevant point to be considered is that, if all consumers (including pho- tovoltaic ones) are billed entirely or primarily through monthly fixed charges, then the cross-subsidization issues will not be eliminated, despite of changing in comparison to other rate structure options. as with the current volumetric rates, homogeneous fixed tariffs would not consider, nor reflect, how prosumers impose different kind of costs to the utilities (regarding the different kind of services they demand from the grid) and/or offer benefits to the utility system. in this regard, the effects of raising fixed charges are ambiguous and, in the worst case, it would change who is subsidizing whom (bird et al., 2013).

studies developed recently claims to measure the impact of fixed monthly charges on pVdG customer-economics. The results found in each of them are closely related to the assumptions regarding the size of the fixed charge and whether the charge is associated to a corresponding reduction in volumetric charges. an analysis of a recent

$7 increase to monthly fixed charges in Wisconsin found that the corresponding reduc- tion in volumetric rates would lead to a roughly 15% reduction in the bill savings from prosumers (KaNN, 2015). another analysis about the possible impacts of adopting fixed charges in Massachusetts found that a hypothetical $10 increase in fixed customer charges would increase the total bill for a representative residential solar customer by approximately 9% (Cornfeld and Kann 2014,).

3.1.2. Capacity based/demand tariffs

demand charges have been considered a possible solution to the utilities lost revenues and cross-subsidy issues which emerge with dGpV diffusion. in the case of net-metered prosumers, an electricity bill based on the peak demand, for example, could reflect the costs the distribution companies incur in providing grid services to those consumers (bird et al., 2013).

The basic assumption behind the definition of capacity based tariffs is that the investments on grid infrastructure are dimensioned based on the projected peak load.

in this sense, this kind of charge allow the utility to better allocate the non-energy costs of serving individual consumers, as the grid is designed, and the utilities’ capital invest- ment decisions are taken, to meet consumers’ peak demand (bird et al., 2013).

although capacity-based tariffs are treated as a single, uniform tariff structure, there are many possible designs (HleidiK, 2014; HleidiK aNd GreeNsteiN, 2016; sCHitteKatte et al., 2017). two parameters are especially relevant when determining the design of a capacity based network charge, as they have a huge in- fluence on the level of accuracy of the charge in forecasting the peak demand. The first one is the billing cycle of the charge – i.e. “is the peak demand determined on a daily, monthly, seasonally or annual basis to calculate the network charges” (sCHit- teKatte et al., 2017). The second parameter is the duration over which the peak demand is measured, i.e. instantaneously, based on an average over fifteen minutes, average of one or more hours, etc. broadly speaking, the accuracy level of the tariff is influenced the following way: the longer the billing cycle and the shorter the shorter the period over which the peak measurement is averaged, the more inaccurate a tariff is in forecasting the peak demand (sCHitteKatte et al., 2017). Thus, capacity-

based tariffs can be designed in many different ways, and each of them has different effects, such as (Ceer, 2017):

i. tariff based on the highest capacity used in a year: this kind of design is close to a subscribed capacity tariff. as it does not differentiate between capacity used at peak time and capacity used off-peak, it is only partially cost-reflective;

ii. tariff based on the highest capacity used in a shorter timeframe, for instance the highest each month: although it is considered more cost-reflective, it requires smart metering, what can restrict its applicability;

iii. tariff based on the highest capacity used in a very short timeframe (for instance day, or even hour): on the one hand it the most cost-reflexive design; on the other hand, it is extremely complex and less predictable for many consumer groups, what can make it less acceptable to consumers.

one of the positive aspects of demand charges is the inherent incentive for con- sumers to adopt energy efficiency measures and to flatten their load shape, in order to lower their peak demand and so reduce their electricity bills. This change in consumers’

pattern of consumption would also reduce the utilities overall costs of service, as a re- duced peak level would require utilities to acquire less resources (bird et al., 2013).

Hleidik and Greenstein (2016) and simshauher (2016) consider capacity-based charges an attractive option to deal with the challenges discussed earlier. They argue that capacity-based charges would avoid inequitable bill increases and, at the same time, allow for better cost reflection.

one of the limits of this kind of charge are related to the fact there are some fixed costs that do not fluctuate with peak demand (bird et al., 2013).

regarding the impacts of demand charges on net-metered consumers, on the one hand, the corresponding reduction in volumetric tariffs components would reduce bill saving achieved through net metering. on the other hand, this reduction could be partially compensated by consumers load shift (associated to changes in consumption patterns), reducing demand charges (barbose et al., 2016).

schittekatte et al. (2017) also analyze possible impacts of adopting capacity-based tariffs. The authors consider a capacity-based network charge based on the observed peak demand during one hour. Their results show that, with this kind of capacity-based tariff in place, investments in batteries and pV was over incentivized in some scenarios, leading to an increased capacity of der per consumer and subsequent equity issues.

The authors recognize, however, some limitations of the presented results, regarding

not only the restrictions considered in the model, but also the design of the capacity tariff. They state that, for example, a “capacity based charges based on the peak de- mand during 15-minutes with a seasonal or annual ratchet would perform better than the results shown in this analysis” (sCHitteKatte et al., 2017). another issue is that, by considering grid costs to be sunk, the authors focused on the limitations of capacity-based charges. although they recognized that this assumption may not be valid for countries where the distribution grid is being expanded, and thus sunk costs are lower and many investments are driven by future demand forecasts. in this case, the total costs to be recovered by the dso would be a function of network usage.

When comparing fixed and capacity-based network tariffs, some authors consider the latter fairer than imposing the same fixed charge for all consumers within the same consumption class (Costello, 2015). Costello (2015) argues that, due to the ap- parent correlation between demand and energy consumption, it would be unfair to charge both low-usage and high-usage consumers the same fixed costs. in this sense, a demand charge would better reflect cost causation (Costello, 2015).

3.1.3. Hybrid approaches

although much has been discussed about the best rate structure alternative, as it was just presented, there are also many authors who recognize that there is not an only, one-fits-all approach. in general, they propose that hybrid tariff structures are highly recommended.

borenstein (2016) is one of these authors. The main assumption behind his thesis is that “challenges arise as a significant part of the network costs are sunk costs”, and no clear recommendation can be found in economic theory about the better way of allocating such costs, as the cost causation is not clear. Thus, he argues that possibly a combination of higher fixed charges and time-varying volumetric charges would be the least bad option.

time-varying tariffs aims to provide a more efficient price signal to consumers, as tariffs are supposed to reflect the variation of the cost to provide power and grid services throughout the day. besides of incentivizing a more rational and optimal use of the electricity and the grid, time-varying pricing can play an important role in pro- viding system flexibility for integration of renewable, intermittent generation, and for managing der and distribution systems (Cappers et al., 2011; laZar, 2014).

one of the most common kinds of time-based charge are time-of-use (tou) rates, which “charge different prices during the day, typically falling within two or three pre- determined prices and time periods (bird et al., 2013).

brown et al. (2015) do not identify any single option either. However, they argue that setting a multi-part tariff for households – potentially including a fixed charge, a demand charge and a volumetric charge - is closer to being efficient, because the three parts of the tariff have different impacts on consumer behavior.

an important issue when analyzing hybrid tariff structures is the proportion of revenues recovered through each of the tariff components. brown et al. (2015) illus- trate the importance of taking a further look in the weight of the components through the analysis of the italian case. They show that, while in most countries there are no demand charges for household customers, in italy the tariffs structure includes a demand component. the demand charge is small. The weight of the italian demand charge, however, is small, as the charge recovers around 20% of the total revenue.

so, even though the network incurs most costs to supply demand (kW) and almost no costs to supply energy (kWh), a large proportion of revenue is recovered through kWh charges.

reinforcing the thesis that a hybrid tariff structure would be preferable, “both the european literature review and the answers to the eC public consultation on energy Market design indicate a general support for a move towards (…) a hybrid or capac- ity and consumption based charging to incentivize a change in consumer behavior”

(Ceer, 2017, p. 21).

4. Case studies