Elsevier

Applied Energy

Volume 268, 15 June 2020, 114964
Applied Energy

The effect of rate design on power distribution reliability considering adoption of distributed energy resources

https://doi.org/10.1016/j.apenergy.2020.114964Get rights and content

Highlights

  • Develop separate network reliability indices for the consumers and the utility.

  • Focus on distribution networks with behind-the-meter PV and Storage DERs.

  • Implement Monte Carlo simulations to capture the effect of tariff design.

  • Several scenarios for time-of-use rates and their impact on DER adoption & dispatch.

  • Rate design may lead to opposite effects on reliability for consumers vs. the utility.

Abstract

Electricity rates are a main driver for adoption of Distributed Energy Resources (DERs) by private consumers. In turn, DERs are a major component of the reliability of energy access in the long run. Defining reliability indices in a paradigm where energy is generated both behind and in front of the meter is part of an ongoing discussion about the future role of utilities and system operators with many regulatory implications. This paper contributes to that discussion by analyzing the effect of rate design on the long term reliability indices of power distribution. A methodology to quantify this effect is proposed and a case study involving photovoltaic (PV) and storage technology adoption in California is presented. Several numerical simulations illustrate how electricity rates affect the grid reliability by altering dispatch and adoption of the DERs. We further document that the impact of rate design on reliability can be very different from the perspective of the utility versus that of the consumers. Our model affirms the positive connection between investments in DERs and the grid reliability and provides an additional tool to policy-makers for improving the reliability of the grid in the long term.

Introduction

To achieve emission targets, countries need to increase generation share from renewable energy sources, not only as part of the bulk generation system but also at the level of the distribution grid [1], where private owned photovoltaic (PV) systems – installed behind the meter and coupled with electric storage and control technologies – have been seen as an efficient way to increase decentralized renewables penetration. Ambitious policy targets have been announced to promote adoption of these Distributed Energy Resources (DERs) by private consumers, such as the new amendment to the Building Energy Efficiency standard in California that requires new residential buildings to have a rooftop PV unit installed starting in 2020 [2]. Such policy measures will continue driving down the cost of solar panels and related technologies, such as storage, creating conditions for a massive adoption.

Besides the technology costs, mass adoption of PV and storage by private consumers is also dependent on the portfolio of electricity tariffs offered by utilities. In fact, the magnitude and structure of tariffs – including demand charges, energy rates and PV feed-in remuneration – strongly affect the payback period of these investments, acting as a second main driver for adoption [3], [4], [5], [6]. Mechanisms of rate design to promote consumers’ adoption of DERs are presented in [3], [4]. In case of PV adoption, the authors of [5] identify feed-in tariffs as a main socio-economic component for adoption; in [6] the dynamics between retail electricity rates and PV adoption are evaluated.

While not the primary reason for the deployment of DERs, distribution grid security and reliability is also impacted by the presence of DERs, see e.g. [7], [8]. Recent studies have explored the use of utility owned DERs to manage outages and improve the reliability of distribution systems, especially when these DERs comprise dispatchable technologies, such as battery storage [9], electric vehicles (EV) [10], [11] and demand response (DR) [12], [13], or when located in active portions of the distribution system, e.g. microgrids [14]. In contrast, DERs placed behind the meter are outside of utilities’ jurisdiction and therefore can only be indirectly influenced by price signals (e.g. tariffs) to support grid operation [15], [16], [17]. For example, energy [15] and power [16] based dynamic tariffs can be used to indirectly change the dispatch of EVs in order to alleviate congestion. Similarly, time-differentiated energy prices can be offered to incentivize DR behaviours that impact the reliability of the distribution grid [17]. In fact, as shown in [17], time-varying tariffs can produce changes in consumers net load that significantly affect the magnitude and time distribution of reliability indices, such as energy not supplied.

These contributions regarding dynamic tariffs applied to EVs and DR together with the extensive literature on time-of-use (ToU) and peak demand rates demonstrate the effectiveness of tariffs in changing consumption behaviors and, more recently, in indirectly “dispatching” DERs in order to solve medium- and short-term operational challenges of distribution systems. However, as pointed above, the effect of tariffs goes beyond the operational time scale and rate design can be used to indirectly drive long-term adoption of DERs by private consumers. Thus, tariffs could be included in the utility planning process to create favourable scenarios of DER deployment from the reliability perspective.

This paper presents a methodology to quantify the impact of electricity tariffs on the long-term reliability of distribution systems, considering dynamic (tariff-dependent) adoption of DERs by private consumers. This adds another layer of complexity to the reliability analysis performed in [17], by capturing the effect of tariff design both on short-term (dispatch) and long-term (adoption) time scales. To the best of the authors’ knowledge, such methodology does not exist in the literature. It is essential to the ongoing discussion on the new paradigm of rate design in distributed networks with high penetration of DERs [3], [4], [18], [19]. We use the proposed methodology to analyze the effect of different aspects of the magnitude and structure of electricity tariffs on the average energy not supplied (AENS) from the utility, as well as on the actual magnitude and duration of outages experienced by the consumers. In particular, we are able to quantify the positive link between DER behind-the-meter adoption and grid reliability. A case study involving a PG&E 69 node feeder, where consumers adopt PV and storage technologies, is used to illustrate the approach.

The paper is organized as follows: Section 2 presents the adoption model; Section 3 describes the Monte Carlo simulation of system states and the storage model during line failures applied to compute the reliability indices; Section 4 provides a case study where the reliability impact of different aspects of tariff design is evaluated; finally, Section 5 presents the main conclusions.

Section snippets

Adoption model

In this section, we model adoption of behind-the-meter DERs by private consumers, assuming economic rationality in long-term consumers’ decisions related to the acquisition and utilization of DER technologies. This economic rationality is presented as an optimization model, where individual consumers size and dispatch their DER assets in ways that minimize their energy costs. It is important to stress that this approach differs from more complete socioeconomic models of adoption and diffusion

Reliability analysis

This section presents a methodology to perform the reliability evaluation for different tariff scenarios and subsequent adoption of PV and storage technologies. This work builds upon existing reliability methods and indices at the level of the distribution grid, which are commonly used in the power systems reliability studies [7], [22]. More detail about this underlying reliability framework can be found in [23].

It is important to stress that our reliability evaluation is based on the adequacy

Case study

This section discusses the effect of different tariff structures on the adoption of PV and storage technologies by private consumers, along with the consequent impact on the reliability of the system, both from the perspective of the consumers and the utility. We consider the modified PG&E 69-bus [24], [25] MV network (Fig. 1), where each node connects either a Commercial complex (blue diamonds), a public service building (green circles) or a block of Midrise Apartment buildings (red

Conclusion

This paper presented a methodology to quantify the effect of rate design on the long term reliability of power distribution, assuming that electricity tariffs will become a main driver for adoption of DERs (e.g. PV and storage) by private consumers.

Our results show that both magnitude and structure of time-of-use electricity rates influence the adoption and the dispatch of behind-the-meter DERs with significant impact on the outages accounted by the utility and experienced by the consumers. In

Declaration of Competing Interest

None.

Acknowledgment

The authors would like to acknowledge Dan Ton and Ali Ghassemian, Program Managers at the U.S. Department of Energy - Office of Electricity, for the support granted to this work through the Microgrid R&D Program and the Advanced Grid Modeling Program. Aditya Maheshwari and Michael Ludkovski were supported in part by NSF DMS-1736439. We thank the editorial team for several helpful suggestions to improve the manuscript.

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