## 1 Introduction  
Nearly 140 years ago, the world witnessed the emergence of the first electrical grids. In the early stages, electrical grids were localized, decentralized, and unregulated. However, within the next five decades, driven by the increased demand for electricity induced by the second industrial revolution and a pressing need to regulate the energy markets, electrical grids metamorphosed into large, centralized power grids. The early primitive decentralized grids formed the first era of electrical grids, or what we define as Energy 1.0, followed by the centralized architecture that formed the second era, or Energy 2.0 (Figure 1). However, with both Energy 1.0 and Energy 2.0 grids, the consumer was completely dependent on the utility, and the energy flow was unidirectional (Figure 2), from the grid to the end-user. Concurrently, utility companies worldwide were under the continuous pressure of balancing their power generation capacities with the increasing demand, over and above a constantly fluctuating fuel supply market, environmental restraints, and growing end-user expectations [1]. Nevertheless, centralized electrical grids remained a substantial solution  
change led to a new fundamental restructuring of the electrical grid's architecture that no longer relied on centralized power generation plants but was dependent on supply and demand resources mainly located towards the edge of the grid, at the consumers' side. Hence, the new electrical grid became a decentralized grid that encouraged a bidirectional flow of energy, from the grid to the end-user and vice versa, defined in this article as Energy 3.0 (Figure 1). Moreover, at the core of this new Energy 3.0 framework, the consumer became a fundamental stakeholder, a proactive, engaged member in managing the energy grid [3]. The active consumers became prosumers through their investments in clean energy and participation in power generation and demand-side management [4]. In addition, the progression of energy storage systems opened the door for off-grid microgrids [5], and for the first time, end-users were no longer dependent on the utility grid but had the option to be independent (Figure 2). Nonetheless, this energy transition would not have been possible without the proper incentives to encourage consumers to invest in DER solutions. For small-scale projects, billing arrangements such as net metering (NEM) and Feed-in-Tariff (FiT) were adopted [6]. As for medium and large-scale projects, financial agreements such as Power Purchase Agreements (PPAs) were implemented to encourage investments in RE-based power generators [7]. Though microgrids provide a platform to implement more cost-effective DERs, their development faces numerous technical, economic, and infrastructure challenges associated with grid capacity and stability, hindering the wide integration of RE resources and distributed power generation. However, the variable and intermittent nature of RE resources has added a new level of complexity to the current formula [8]. Peak load management and power imbalance have developed into a fundamental dilemma that challenges the proper performance of electrical grids by impacting the quality and reliability of the power supply. Moreover, despite their wide acceptance by prosumers, billing arrangements like NEM and FiT face several limitations and challenges that can be unfavorable for both the utility and the end-user. Among those challenges is the problem of uncompensated excess energy injected into the grid in the case of NEM [9] and the issue of decreasing energy rates in the case of FiT [10]. Over and above, all existing compensation mechanisms share the same disadvantage of not reflecting the cost of electricity at the time of injection into the grid, as well as the lack of a competitive pricing mechanism, where a monopolist, the utility, has the upper hand in fixing the energy rates [11].