These empowered prosumers, as further described in chapters in this volume, can reduce their dependence on the services traditionally delivered by the assets and infrastructure upstream of the meter by increasing their reliance on distributed energy resources (DERS), which by definition, are provided, consumed, and possibly stored locally.

With the expected emergence of affordable storage, some prosumers can go a step further by becoming prosumagers; this they can accomplish by storing the excess generation for use at later times. With zero net energy (ZNE) buildings a virtual reality,¹ it is not far fetched to envisage some prosumagers operating virtually independent of the grid for the most part, relying on the network only sporadically, for balancing services and reliability (Fig. 1.1).

Add a host of new intermediaries with sophisticated capabilities who can aggregate flexible loads and distributed generation—which can be effectively bid into wholesale markets—and one can see the power of aggregation enabled by automated machine-to-machine (M2M) communication. Advances in artificial intelligence (AI) are likely to lead to proliferation of services offered by such intermediaries who can provide valuable services to grid operators and distribution networks, while better managing energy consumption and reducing participants’ energy service costs. Examples of such aggregators may be found in chapters by Löbbe & Hackbarth, Johnston, and Steiniger, among others.

However, innovation and disruptions don’t end there. There is increased interest in transactive energy and peer-to-peer (P2P) trading facilitated by platforms that allow consumers, prosumers, and prosumagers to better manage their consumption, distributed generation, and storage, and not just internally, but with their neighbors and among their peers. While many regulatory obstacles remain to be resolved, the distribution network physically connecting the participants is already in place.

Bitcoin and blockchain technologies²—among others—offer new opportunities for such transactions to take place among and between consumers using the existing distribution network and related infrastructure.

Microgrids, another promising emerging technology, offer individual customers and/or a collection of customers to better manage their consumption, distributed generation, and storage, allowing them to operate independent of, or parallel to, the supergrid as described by Knieps.

A combination of these is likely to enable some prosumers to operate virtually independent of the traditional grid, or in the extreme, go off-grid. While this is not a viable option for most, it may be an option for some, especially if the prevailing regulated tariffs are not cost-reflective and/or offer perverse incentives for consumers to make additional investments that enable them to operate more or less independent of the grid.

As noted in the 2016 MIT report on Utility of the future,³ the perverse economics of grid defection may be among the unintended consequences of regulated tariffs that predate the recent rise of DERs.

This chapter offers the editor’s own views on the likely evolution of DERs and their potential impact on the incumbents. Section 2 examines the economics of DERs versus traditional bundled service at regulated tariffs. Section 3 examines the consequences of the bifurcation of customers into consumers and prosumers. Section 4 examines the potential impact of aggregators, intermediaries, and others who are likely to take advantage of new opportunities in the changing business environment. Section 5 speculates how a regulators’ role is changing in response to the preceding discussion, followed by a summary of how the book is organized and highlights of each chapter as a quick guide to readers.

Making matters worse for the incumbents in the power sector, in many European countries, Spain and Germany in particular—both featured in this volume—the regulated tariffs are loaded by myriad of levies, taxes, and other surcharges that have virtually nothing to do with the actual cost of generating and delivering electricity to customers. In some cases and for some classes of customers, these surcharges may compromise nearly half of the regulated tariff measured by the cents/kWh. In many countries and parts of the United States, residential retail tariffs are in the 20–30 cents/kWh range, sometimes even higher, such as in Hawaii or Denmark.

By contrast, the costs of DERs, be it energy efficiency in the form of efficient lighting, TVs, refrigeration, HVAC, or services delivered by appliances, or distributed generation in the form of rooftop solar PVs, have been steadily falling.

As many pundits have been saying for years, at some point in some places, the cost of DERs is bound to fall below the cost of buying electrons from the grid—the crossover is often referred to as price parity.⁴ And it should come as no surprise to anyone that this has already occurred in some places, and is likely to happen elsewhere over the next decade if not sooner.

And when that happens, consumers are better off to consume less (by investing in energy efficiency) and self-generate more (by installing solar PVs or other generation options when feasible). By doing so, they avoid paying for more expensive grid-supplied electricity.

This new reality has interesting implications for developing countries that currently lack the extensive and expensive grid infrastructure that is already in place in the developed world. In some cases, developing economies may be better off to develop semiautonomous microgrids to serve rural customers who currently do not have access to electricity services, rather than wait for the supergrid to expand to serve them.

The economics of DERs are further fortified by a variety of financial incentives and support schemes such as net energy metering (NEM) laws in the United States and feed-in-tariffs (FiTs) in many European countries, as further described in chapters that follow.

In the case of NEM, the incentives to self-generate are immensely boosted because consumers not only avoid paying for expensive kWhs, but also can virtually eliminate their entire electric bill by feeding as much into the network as they withdraw from it (Fig. 1.2). As there are little or no fixed fees in many parts of the United States for residential customers, this is not uncommon for many solar households and even some commercial ones.

In states, such as California, where retail tariffs are tiered⁵—that is the rate rises at the margin at higher consumption volume—and can be as high as 36 cents/kWh, it is not uncommon to find solar customers who pay virtually little electric bills. Needless to say, such customers—in the absence of reasonable fixed fees or connection charges—do not adequately contribute to the maintenance and upkeep of the network, which they continue to rely on to balance their variable consumption and self-generation.

Aside from the attractiveness of self-generation are major advances in energy efficiency in buildings, lighting and appliances, which makes them ZNE, that is, they consume very little and generate enough to offset their meager usage (Fig. 1.3). The net results are zero or virtually zero electric bills, if tariffs are solely or mostly based on volumetric consumption. California regulators want all new residential buildings to meet the ZNE standard by 2020; the same would apply to new commercial buildings by 2030.⁶

The writing, one might say, is already on the wall. The rise of DERs is likely to reduce net reliance on the grid for kWhs at first, and possibly other services as some consumers become prosumers and possibly, eventually prosumagers.

Regardless of the specifics, consumers who invest in DERs—or in some cases lease them rather than an outright purchase as in the United States—become prosumers (Fig. 1.4). They buy less from the grid, while injecting their excess generation into the distribution network, and this, as amply described in MIT’s Utility of the Future report, has a significant impact on the distribution network depending on when, how much, and where the offtake or injection happens. The impact can be positive, negative, or neutral depending on the specifics of when, where, and how much; the details go beyond the scope of this chapter.

The issue of consumers versus prosumers—or solar versus nonsolar customers—has already surfaced as a highly contentions and politically charged topic, especially in the United States, where generous NEM laws are currently in place in around 40 states. Multitudes of studies, for example, allege that solar customers as a class tend to be more affluent and what they save by reducing their net consumption from the grid ends up as extra costs that must be borne by the remaining nonsolar customers.⁷

This has naturally led to efforts to introduce fixed fees, connection charges, minimum bills, solar exist fees, and similar regulatory schemes to reduce or eliminate the alleged cost shifting. As described by Baak in this volume, it must be noted that the debate about who is subsidizing whom in the DER space can be highly convoluted because stakeholders with different vested interests have opposing views and present convincing evidence to support their positions.

Setting that aside, it is fair to say that the bifurcation of consumers and prosumers has become contentious, and the regulators, who must find a balance between what is good for the former without jeopardizing the options of the latter—often in the context of broader environmental, societal, and policy objectives—are caught in the cross fire.

There is apparently no easy fix. For example, if the existing NEM laws are modified or voided—as recently happened in the state of Nevada—prosumers who have already invested in solar panels may be tempted to go a step further by investing in distributed storage, improving their ability to store the excess generation for use at later time. Moreover, this will enhance opportunities for energy management while allowing them—potentially—to engage in P2P trade with other customers whose consumption pattern may be different than their own, making their building into a ZNE fiefdom, joining other like-minded prosumers and/or aggregating their consumption and storage in such a way to avoid paying the new fees imposed on them.

In short, if the incentives to sell the excess generation into the grid are reduced or removed, some prosumers may decide to go a step further by becoming prosumagers. Investing or joining semiautonomous microgrids or shared community schemes—as covered in chapters by Knieps and Koirala & Hakvoort—may become even more appealing to such prosumagers.

Future innovations and disruptions to the status quo utility business model cannot be ruled out, as further described in chapter by Jones et al, Löbbe & Hackbarth and Orton et al. This goes to the core of the message in chapter by Smith & MacGill about the need for a “great rebalancing act” and explanations of Woodhouse & Bradbury on how innovation and disruptions will lead to “the survival of the fittest.” Likewise, Webb et al. argue that with the continued fall in the cost of distributed solar a new class of customers—large commercial and industrial establishments with much bigger roofs, bigger electricity bills, and more resources—will join residential consumers who have largely been going solar to date. Haro et al. offer more sophisticated dynamic network tariffs to address some of these vexing issues.

Moreover, new service options are emerging, offering customers, such as apartment dwellers who cannot physically install solar panels on their roofs, to participate in the DER revolution by becoming virtual solar or renewable customers as described in chapter by Johnston.

This suggests that the bifurcation of customers into those who are and will remain totally reliant on the existing grid for all their electricity service needs and those who may become selectively and sporadically reliant on the grid has only started.

In many countries—Germany is a prime example—a significant percentage of generation is already distributed and largely produced from variable renewable resources. In California, the investor-owned utilities (IOUs) have already exceeded 5 GW of distributed solar rooftop, as mentioned by Michael Picker in the book’s Preface. Australia, with a fraction of the US population, already exceeds 1.5 million solar roofs and counting, roughly the same number as in America.

Making the role of aggregators, integrators, and intermediaries even more urgent is the fact that much of the utility-scale generation is also becoming renewable, which means increasingly variable and nondispatchable as described by Steiniger and Webb et al. In many countries, Denmark, Germany, Spain, Portugal, Ireland, to name a few, the grid operators are already increasingly challenged trying to balance variable generation with demand. It is not just the traditional utility business models that are being challenged, but so are traditional grid-operating and dispatching models, which calls for new perspectives, as explained in chapters by Cooper and Knieps.

Without doubt, this space—the growing role of aggregators, integrators, and intermediaries—is likely to have the biggest impact on the future of the power industry. New entrants, such as Next Kraftwerke⁸ and its cohorts, provide a mere glimpse of what is likely to follow.

There will, however, likely to be many others who will find profitable ways to disrupt the traditional ways of doing things at every step of the utility value chain. One example is the recent merger of Tesla with SolarCity. Elon Musk, the CEO of the combined enterprise, has outlined his vision of an integrated energy, mobility, and storage service by combining Tesla’s electric cars with SolarCity’s distributes generation, and its Powerwall distributed storage. Webb & Wilson provide further details on the likely evolution of EVs, including autonomous ones, and their impact on the utility business, both positive and negative.

In a blog posted at Tesla’s website describing his vision for a fully integrated company, Musk wrote:

Perhaps it will not be quite as simple as Musk claims, but his vision to create an integrated energy services model that is far less complicated than today is not just likely, but definitely on target. Moreover, there are other advantages to integrating energy generation, consumption, storage, trading, mobility, and management. In the case of Tesla, this includes much better use of Tesla’s ubiquitous and fancy car showrooms, which can now sell solar PVs and storage batteries under the same roof. One company, one contract, one point of sale, and one integrated bill for a host of integrated services. Clearly Musk is not the only clever entrepreneur trying to disrupt the protected monopoly business model of traditional utilities.

With the approval of the merger, in theory, Musk can now bundle electric mobility, solar PV panels, and storage into an integrated product/service combination that appears to many affluent consumers; those who can afford an upscale EV, may be interested to generate some of their electricity on their roofs, and may wish to store some of the extra generation into a battery for use at another time.

There are many who speculate that integrators, such as Tesla, will not stop there. With their access to valuable data about when their clients use energy, when, and how much they generate, and when and where they store it—including their EVs—newcomers, such as Tesla, can easily manage the entire energy profile of their portfolio of customers. Going one step further, they can use this portfolio of distributed load, generation, and storage to sell valuable services to the distribution network operators.

When, for example, part of the distribution network is stressed or needs frequency or voltage support, the aggregators/integrators can reroute some of the generation or stored energy to alleviate the congestion or control frequency or adjust voltage levels.

The projected rapid rise of EVs, described by Webb & Wilson and Alvarez suggests that depending on when, where, and how they are charged and discharged will have significant impact on the future of the distribution network. In their chapter, Orton et al. describe other business plans and models to integrate electricity generation, delivery, and storage services. Many more are likely to emerge.

For the first century of its existence, major innovations and most of the investment were upstream of the meter. The reverse is likely to be the case in the second century, as the rebalancing of the electricity’s value chain takes place, as further elaborated by Smith & MacGill. The rising stars of the second century are likely to be the aggregators, integrators, and intermediaries. Their success will increasingly be driven by better management of the data, while offering convenient services, seamlessly and efficiently.

This is likely to put tremendous strain on the regulators around the world who must find a balanced approach to allow—in fact facilitate and encourage—innovation to serve the needs of presumes and prosumagers, while protecting the interests of consumers who may be more or less content with the status quo. Finding the proverbial level playing filed, often mentioned in this context, will become more challenging and pressing.

This volume is blessed by having contributions from four prominent regulators from four different parts of the world, who are sharing their perspectives in the Foreword, Preface, Introduction, and Epilogue.

As this editor sees it, two key issues stand out among the many facing the regulators:

Regarding the former, designing fair, and reasonable rates—the fundamental guiding principle for regulators—most experts agree that tariffs must correctly reflect the true cost of service. As described in MIT’s Utility of the Future report, to get the prices right, tariffs must correctly reflect the four main components of cost of service:

Currently, these components are bundled in regulated tariffs, usually in highly opaque and nontransparent ways. They are neither obvious to most consumers, nor are they logical from a technical or economic perspective. This increasingly leads to decisions that may make sense to some prosumers or prosumagers, while making little or no sense when viewed from the broader perspective of the society at large.⁹

Moreover, retail tariffs tend to be flat and postage stamp. They do not vary by time, location, peak demand, or pattern of usage. This is another major deficiency, highlighted in a number of chapters in this book, including Biggar & Dimasi. Moving to more granular tariffs, both on spatial and time dimension, would better capture the actual costs of service, but can make them more complicated than most customers can understand. For example, Baak, in his chapter, describes a number of initiatives in the state of California to move toward more granular and cost-reflective tariffs.

The technology is increasingly available and affordable to design and implement more granular and sophisticated tariffs, but regulators, for the most part, appear reluctant to make major steps in adopting them, favoring a gradual approach.

After examining a host of technical issues, MIT’s Utility of the Future devotes a lengthy chapter with multitudes of recommendations—30 to be exact—for regulators to consider. Likewise, a recently released manual by the National Association of Regulatory Utility Commissioners (NARUC) offers a rather lengthy discussion on how to treat DERs.¹⁰ The Essential Energy Services, the regulator in the state of Victoria in Australia recently released a report on how to enumerate DERs, focusing—among other things—on the value of distributed solar PVs on the distribution network.¹¹ Clearly, this already is and will likely remain a hot area for research, and debate, for some time.

Opinions vary on the topic of how to regulate the use of, and access to, the critical distribution network. As described by Audrey Zibelman in the Introduction, the regulators in the state of New York have embarked on a bold initiative called reforming the energy vision (REV). At its core, REV provides guidelines on who should pay for, who should maintain, and who can use the distribution network. Beyond that, the stakeholders are free to innovate, disrupt, and offer new products and services. The aim in New York, and elsewhere, clearly is to move toward a regulation fit for the emerging distribution network of the future.

Regulators in other states are taking different approaches, depending on the circumstances. In California, for example, it has been suggested that IOUs be allowed a regulated rate of return for investing in DERs, as is currently allowed for approved and prudent investments upstream of the meter. As explained by Baak, while this may sound like a good idea, it clearly makes the regulator’s life even more complicated, as they must now decide how much investment in DERs is prudent, necessary, and cost-effective, as they currently do for upstream investments.

In his chapter, Gellings argues that despite all the hyperbole on DERs leading to utility death spiral and worse, the industry’s traditional rate of return regulation “ain’t broke and it don’t need fixing,” the subtitle of his chapter. His proposal is not to throw the baby out with the bathwater.

Just as IOUs in many states, notably California, have been persuaded to engage in improving the energy efficiency of their customers—a counterintuitive measure under the traditional rate of return regulation—they can in principle be encouraged to do the same for DERs, by investing on the customer side of the meter, when it is efficient and cost effective to do so.

Once again, it is easier said than done. An example of the difficulties has surfaced in the debate on who should invest in electric charging infrastructure: IOUs; electric car companies, such as Tesla; municipalities; new private companies; or a combination of all of these? Everyone agrees that this is a classical chicken and egg problem: customers will not buy EVs in sufficient numbers unless there is a charging infrastructure in place, while car companies will not invest in EVs unless there is a market for them.¹²

Other pundits who are exploring the future of utility business models have suggested that the power sector is on a path not unlike that of the mobile phone industry. Today, most mobile phone users pay a fixed monthly fee based on a 2- or 3-year contract with a network service provider.

The explanation is simple, while the analogy may not be perfect. Mobile phone service is increasingly about connectivity and access to the network. It is like a membership in a gym or a private golf course. It is not about volume or frequency of usage.

Customers choose a mobile phone network not only on the basis of cost, but also on the ubiquity of network access—the strength of the signal—bandwidth, and speed. They are rarely charged on a per-call or per-minute basis these days. The cost of service is much better reflected, and collected, through a fixed fee almost regardless of volume of service, say the number of minutes called, number of e-mails sent, etc. Gone are the complicated and lengthy bills that spelled out each call number plus time and length of call, whether it was between 9 a.m. and 5 p.m., or in the evenings or weekends. Younger readers probably don’t even remember such phone bills.

The same, one can argue, applies to many other services where the bulk of the costs are fixed as in the membership in the gym or garbage collection service. It makes little sense to weigh the garbage being collected each week or charge the customer every time (s)he shows up at the gym.

The electric service, these pundits argue, is moving in the same direction. As much of the new generation is coming from renewable resources, both utility scale and distributed, the cost of electrons—the commodity portion of service—is rapidly falling, eventually approaching zero.¹³ When that happens—which is already the case in many places—it makes little sense to charge any or much for the energy or generation component of service, it is often argued.

Moreover, with the advent of ZNE buildings, the volume of consumption is likely to be flat or falling. This is already happening in many advanced economies. The implication is rather clear: tariffs based exclusively or primarily on volumetric consumption are unlikely to deliver sufficient revenues.

Taking this argument a step further, why not charge customers mostly for being connected to the network, making the electrons free or mostly free? That would make it similar to mobile phone service. After all, the most valuable feature of the grid is the reliability and the balancing services that it provides, for both consumers and prosumers.

This is essentially what one senior California utility insider suggested as the best option going forward. When rhetorically asked what he thought was the simplest way to cover the cost of electricity service in the future, he said that if every residential customer paid a fixed $2 per day, he would offer kWhs at 5 cents/kWh in each direction; whether buying from or selling to the grid.

To put this in perspective, current residential rates in California range from 11 to 36 cents/kWh depending on the tiers—hence 5 cents/kWh represents a substantial discount even from the lowest tier. This particular utility has over 5 million residential customers who currently pay virtually no fixed fees. Under his proposal—in the context of a private conversation and a rhetorical question—the utility would collect $300 million per month plus what is applicable from the net volumetric consumption at 5 cents/kWh. Presumably, the fixed fees would go toward the fixed component of maintaining the grid, while the volumetric component would cover the variable component of costs, including generation.

Taking a broader context, currently there are 144 million electric meters in the United States, according to the latest annual survey by the Federal Energy Regulatory Commission (FERC).¹⁴ If every meter—for the sake of simplicity—were to pay $2/day for being connected to the “grid,” that would amount to over $105 billion per annum, a significant amount toward the upkeep and upgrading of the network.

Ridiculous? Apparently not. The average US residential consumer pays roughly $110 per month for electricity (Table 1.1), of which an estimated 55% is fixed costs.¹⁵

A few experts and scholars who have examined the future of network and how to best pay for it would go even further. Some argue that for all but customers, who choose to go totally off-grid, the network can be viewed as a “social good” in the same sense as public libraries or public schools are. The society pays for their upkeep, regardless of how often or how extensively they are used by individuals. For example, singles, unmarried people, childless couples, or those who send their kids to private schools currently pay the same property taxes, which cover the cost of public schools in many parts of the world. The logic is that the society is better off when such services are provided and supported by all, regardless of the level or frequency of usage.

After analyzing the temporal and spatial distribution of costs and benefits and designing sophisticated tariffs that reflect the granularity of costs and benefits, why not socialize the fixed cost of the distribution network, so that it is supported by all and available to everyone? In such a future:

After carefully examining and contemplating the many insights of the following chapters—the editor was richly rewarded by reading every chapter multiple times during the editing process—the best that can be said is that the longer-term impact of DERs is likely to be influenced—or determined, if you prefer—by the confluence of three critical factors, as illustrated in Fig. 1.5:

The outcome, in other words, is likely to be different in different parts of the world mostly due to differences in regulations, as the other two factors apply more or less equally everywhere.

Part I. Envisioning the Future. This part of the book examines why and how the industry is changing and speculates on the implications of change on incumbent stakeholders and new players.

In Chapter 2, Innovation, Disruption, and the Survival of the Fittest, Stephen Woodhouse and Simon Bradbury outline the changing nature of the utility business and the struggle for survival—and the relationship with customers—that the incumbent utilities face.

The authors set out a possible model for a customer-centric utility of the future, in which less emphasis is given to ownership of hardware, and customers themselves are treated as core assets. Alternative futures are examined, in which the existing companies are forced upstream by entrants that take over the customer relationship. In that alternative world, there is a further question over whether incumbent companies could extract value from assets and trading, or whether the value will reside with the customer relationship.

The chapter’s key contribution is to set up framework to compare alternative future business models, for incumbent utilities and new entrants.

In Chapter 3, The Great Rebalancing: Rattling the Electricity Value Chain From Behind the Meter, Robert Smith and Iain MacGill look at how distributed generation is shifting the traditional balance between generation, transmission, and distribution toward customer end uses. It identifies and quantifies the substantial oft-unrecognized investment made by customers in the energy value chain, through more efficient appliances, equipment, wiring, and building design.

The authors consider the extent to which the new business models being developed around DERs, such as the NY REV, are anchored in the value creation behind the meter, yet still reliant on the ongoing operation of the grid.

The chapter’s main contribution is to ask if DERs result in value duplication rather than value creation; will this create sunk costs in the grid or see a rebalancing of the grid’s functions and charges to reflect new values across the energy chain.

In Chapter 4, Beyond Community Solar: Aggregating Local Distributed Resources for Resilience and Sustainability, Kevin Jones, Erin C. Bennett, Flora Wenhui Ji, and Borna Kazerooni discuss current developments in community solar. Communities have actively participated in community solar arrays often through group net metering with their utility. While these arrangements have helped community members source more of their energy needs from clean local resources, they fall short of allowing communities to achieve sustainability or energy resilience.

The authors explore alternatives for communities to develop DERs, such as battery storage, demand response, biogas, and microgrids, which increasingly offer opportunities for communities to advance beyond community solar by examining examples, including Marin County, California, and Westchester County, New York to develop a model for community choice aggregation that achieves these goals.

The chapter describes community choice aggregation as means of bringing DERs together for community sustainability and resilience at the grid’s edge.

In Chapter 5, Grid Versus Distributed Solar: What Does Australia’s Experience Say About the Competitiveness of Distributed Energy? Bruce Mountain and Russell Harris point out that in South Eastern Australia’s 4 regional electricity markets, 21 retailers compete to supply a little over 9 million residential and small customers offering over 5400 different retail packages at any one time.

Using currently available information on distributed generation and storage costs, the authors use currently available offers to assess the economics of distributed generation compared to the grid-supplied alternative.

The chapter’s main contribution is to provide insight into the relative economics of grid versus distributed. After all, the relative cost of the two options should dictate the demand for each with significant implications for the future development of retail electricity markets.

In Chapter 6, Powering the Driverless Electric Car of the Future, Jeremy Webb and Clevo Wilson look at the effect on power demand of likely transformative changes to urban transport. This is being ushered in by the simultaneous emergence and impending fusion of all-electric automotive power trains and autonomous vehicles.

The authors examine the reasons why autonomous vehicles will most likely be all electric (EVs), and largely shared. Provided are projections of the likely rate of uptake of EVs and SEAVs, which indicate a substantial reduction in vehicle numbers. Key determining factors examined are expected rates of technological change in car battery storage capacity and autonomous driving systems, and comparative costs of conventional and all EVs and socioeconomic drivers influencing modal choice.

The chapter highlights that a rapid uptake of EVs and SEAVs will have major implications for electric power utilities in terms of its effect on both the overall demand and distributed power storage capacity.

In Chapter 7, Regulations, Barriers, and Opportunities to the Growth of DERs in the Spanish Power Sector, Eloy Álvarez Pelegry explains that generous regulatory support for utility-scale wind and solar investment in Spain encouraged massive investments with serious financial implications. This, in turn, has resulted in a reversal of regulation with implications for the deployment of DERs, including decentralized solar PVs in sunny Iberia.

The author points out that the dramatic drop of photovoltaic costs and the potential reduction of electricity storage prices promises significant opportunities for developing self-consumption and alternative fuels for transport, such as charging EVs.

The chapter examines the Spanish regulatory context taking into account the European objectives for 2020 and 2030 that imply increased reliance on renewables, focusing on the evolution of the regulation and the barriers and opportunities for the development of DERs mostly for self-consumption.

In Chapter 8, Quintessential Innovation for Transformation of the Power Sector, John Cooper introduces the Pace Problem, a fundamental challenge to business transformation strategies in circulation today. Despite relative advances made by utilities in adapting to changes, more aggressive, speedier change outside the industry leaves utilities falling behind, raising consequent risks to long-term stability in this essential industry.

The author proposes a framework for iterative innovation to accelerate the pace of change inside individual utilities and the industry as a whole. Moreover, this framework, in five parts, is tied to a five-part business transformation maturity model, to create a standardized platform for change labeled Quintessential Innovation.

The chapter’s main contribution is to recognize the Pace Problem, a crucial barrier that blocks a critical industry from adapting to a complex future, and offer a compelling solution; borrowing successful best practices from other industries to accelerate adaptation to change.

Part II. Enabling Future Innovations. This part of the book examines the role of policy, regulations, and pricing and how the confluence of these influences the ultimate outcome.

In Chapter 9, Bringing DER Into the Mainstream: Regulations, Innovation, and Disruption on the Grid’s Edge, Jim Baak highlights the challenges regulators, utilities, DER providers, and prosumers face in balancing their conflicting needs and competing interests to enable reliable and cost-effective deployment of DER for the benefit of the grid and consumers.

The author outlines the significant challenges and opportunities of integrating higher levels of DER deployment and the steps necessary to achieve this outcome, which call into question not only conventional grid planning and operations, but also traditional utility business models. At the center of the debate is how will the grid be used and who will pay for it.

By drawing from the experiences of California and New York, the author illustrates different regulatory approaches and offers insights on how best to balance the competing needs of energy users, producers, and regulators, while improving the reliable operation of the grid.

In Chapter 10, Public Policy Issues Associated With Feed-In Tariffs and Net Metering: An Australian Perspective, Darryl Biggar and Joe Dimasi explore how tariff policies affect pressure for net versus gross metering, embedded networks, and P2P trade.

The authors argue that as long as retail prices are artificially inflated and time averaged, policymakers face an unenviable choice: if embedded generation is paid a different (cost-reflective) price, the end customers have efficient incentives regarding the usage of and investment in embedded generation, but at the same time they have a strong incentive to find ways to offset the output of that generation against their own consumption, and that of their neighbors. On the other hand, if embedded generation is paid the retail price, the incentives to use and to invest in that embedded generation are inefficient.

The chapter’s main conclusion is that net metering, and P2P trade will remain controversial as long as retail tariffs are not cost reflective.

In Chapter 11, We Don’t Need a New Business Model: “It Ain’t Broke and It Don’t Need Fixin,” Clark Gellings takes a contrarian perspective by contending that the traditional regulation that has served the industry well—if not perfectly—is not fundamentally broke, and can be modified to serve us in the future.

The author is not convinced that “we” need a new business model for distributional utilities, while acknowledging the dramatic changes in the cost and performance of DERs, energy storage, and hyperefficiency appliances, as well as consumer interest in having control over energy.

The chapter’s main point is to argue that there is nothing conceptually wrong with the existing regulatory model based essentially on the rate of return regulation and suggests that, if properly applied, it can continue largely as it was conceived. In fact, it will lead to a preferred basis for the distribution utility of the future.

In Chapter 12, Toward a Dynamic Network Tariffs: A Proposal for Spain, Sergio Haro, Vanessa Aragonés, Manuel Martínez, Eduardo Moreda, Estefanía Arbós, Andrés Morata, and Julián Barquín explain that new technological developments, and in particular behind-the-meter devices have rendered traditional tariff structures obsolete and induce socially undesirable decision making. On the other hand, they also bring their own solution, in the guise of advanced tariff structures made possible by smart meters.

This chapter proposes a dynamic, “real-time” access tariff methodology motivated by recent developments in Spanish regulations, although the issues are relevant for other systems. The proposal efficiently incentivizes distributed generation and storage deployment, as well as DERs.

The chapter’s main contribution is based on an analysis of the smart meter infrastructure currently being deployed, concluding that the tariff is feasible, robust, provides socially desirable incentives, and allows streamlining of an increasingly baroque regulatory system.

In Chapter 13, Internet of Things and the Economics of Microgrids, Günter Knieps points out that microgrids consist of two complementary parts: a physical low-voltage electricity network; and a virtual network consisting of a complementary set of ICT components for two-way communications. The former can be connected to the latter via Internet of Things (IoT) consisting of physical objects embedded with sensors and electronic chips, and connectivity to virtual networks based on All-IP communication infrastructures.

The author analyzes the potentials of ICT for the organization of future microgrids, including the role of standards for home networks, smart metering and sensing networks, the role of multiple virtual networks for cooperation or integration between different microgrids, and pricing strategies within networks.

The chapter’s main contribution is a systematic analysis of the ICT innovation potentials and the incentive compatible pricing strategies within microgrids taking into account the welfare improving outside options for microgrids.

Part III. Alternative Business Models. This part of the book examines a number of scenarios for how the developments of preceding chapters may shape the future of DERs on the grid’s edge, the theme of the book.

In Chapter 14, Access Rights and Consumer Protections in a Distributed Energy System, Fiona Orton, Tim Nelson, Tony Chappel, and Michael Pierce note that distributed technologies are delivering energy in ways that were not contemplated when regulations governing consumer rights and protections in the Australian National Electricity Market were developed.

The authors examine the rapid uptake of technologies like air-conditioning and rooftop solar, and the potential for battery storage, EVs, virtual power plants, and other energy management products. They contrast the licensing requirements for traditional and nontraditional energy suppliers, and the processes for approving grid connections for technologies in different jurisdictions.

The chapter concludes that the types of grid services that communities consider to be “essential” may evolve over time, leading to redefined access rights. As the definitions of consumers and suppliers become blurred, consumer protection reforms will need to balance innovation and consumer choice with universal access to essential services.

In Chapter 15, The Transformation of the German Electricity Sector and the Emergence of New Business Models in Distributed Energy Systems, Sabine Löbbe and André Hackbarth point out to a growing number of concepts, including P2P trading and transactive energy ushering in innovative services and unorthodox business models.

The authors examine a number of such models covering technology, regulatory framework, market potential, customer segments, and the value creation potential of these business models, including energy storage systems and new forms of partnerships, trading, and aggregation.

The chapter’s main contribution is to examine the viability and potential impact of such business models that operate in small-scale prosumer networks and envision under what conditions such schemes would prosper and grow and what might be their relevance for future DER developments.

In Chapter 16, Peer-to-Peer Energy Matching: Transparency, Choice, and Locational Grid Pricing, James Johnston describes how P2P energy matching could support the transformation of the traditional energy industry into a digital, decentralized, and renewable-powered one.

The chapter introduces the P2P energy-matching concept, using UK start-up Open Utility as an example. It presents the first commercial use case for P2P energy matching: providing customers with transparency and choice over their renewable energy supply.

The author also presents Open Utility’s proposed modification to UK Distribution System Operator (DSO) charging regulations to incorporate locational pricing, and concludes with an overview of how P2P energy matching can lead the development of a community-driven and democratized energy industry.

In Chapter 17, Virtual Power Plants: Bringing the Flexibility of Decentralized Loads and Generation to Power Markets, Helen Steiniger points out that the rapid rise of variable renewable generation in markets, such as Germany, has reached levels that can no longer be managed through the traditional approaches where different types of thermal plants were dispatched to meet variable demand.

The author argues that in the future, increasing amounts of flexible demand and generation must be dispatched in response to variable renewable generation. The chapter describes the concept of a virtual power plant, where the load of numerous consumers with flexible demand and generators with flexible output are aggregated and bid into wholesale markets.

The chapter’s main contribution is to illustrate how Next Kraftwerke, a German VPP, has developed a successful business model around the concept and why similar efforts will be needed in other markets where renewables make up a rising share of the generation mix.

In Chapter 18, Integrated Community-Based Energy Systems: Aligning Technology, Incentives, and Regulations, Binod Koirala and Rudi Hakvoort describe the concept of integrated community energy systems (ICESs), where clusters of residential- and community-level DERs provide a viable alternative to present centralized energy supply system. Although technologies to realize such local energy systems are emerging, the regulatory incentives and institutions to govern them are not.

The authors address a number of critical barriers discouraging further development of ICESs, such as ownership and governance issues, design of local energy exchange, market access of commodities and services, as well as mechanisms for fair allocation of revenues and costs.

The chapter’s main contribution is to outline an institutional design of ICESs from a technoeconomic perspective to achieve economic efficiency and fairness for all stakeholders, and to ensure localized sustainability of ICES initiatives, realizing that such institutional settings need to adapt with the changing DER landscape.

In Chapter 19, Solar Grid Parity and its Impact on the Grid, Jeremy Webb, Clevo Wilson, Theodore Steinberg, and Wes Stein observe that market forces rather than subsidies will drive a much more diverse mix of PV-based prosumers. Further cost reductions for PV and its locational flexibility means its appeal to commercial and industrial customers is likely to be particularly rapid; the same for urban fringe and remote rural regions where grid connection is uneconomic.

For many such customers, the reliance on the grid will be limited, as daylight PV power generation matches demand. However, as renewables reach a critical proportion of energy generation, flexible concentrated solar power will be needed for backup.

The chapter’s key message is that the size and economic function of the greatly expanded class of corporate prosumers will determine the renewable mix, the relationship with the grid, and corporate power purchase agreements (PPAs) with utilities.

In the book’s Epilogue, Johannes Mayer provides an overview of the issues covered in the book and how the insights presented can assist regulators and policymakers to further support innovation and disruption, while maintaining the reliability of the network for those who remain totally or partially dependent on it.