The natural conclusion by the critics of the existing regulatory paradigm is to say that regulation, as currently practiced, has outlived its usefulness; hence the need for a new regulatory regime, new business models, new tariffs, etc. Others have offered that transactional energy is the ultimate solution and that utilities’ usefulness has passed us by. The purpose of this chapter 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, can continue largely as it was conceived. In fact, it will lead to a preferred basis for the distribution utility of the future.

This chapter is organized in seven sections, followed by the chapter’s conclusions. Section 2 revisits the driving force behind the discussions about today’s distribution utility business model; Section 3 offers an opinion for more changes; Section 4 describes the focus of a new regulation using the existing model; Section 5 discusses the rate of return regulation; Section 6 discusses as to why we do not need to reinvent the wheel; Section 7 discusses how we can move forward; and Section 8 compares the existing regulatory model to transactive energy (TE).

Until recently, the relationship of electricity demand to these factors was straightforward. Now with the advent of cost-effective PV power generation, the expanding use of combined heat and power (CHP), and dramatic changes in the end use of electricity, the equation changes. Consumer demand for electricity is now potentially supplied by a combination of grid-supplied energy services and power generated on-site.

Beyond distributed generation, the advent of a myriad of other new and improved technologies also has a substantial impact on the technology landscape and then the overall demand for energy. Recent adoption of plug-in electric vehicles (PEVs) is a prime example of new technologies that can significantly increase the use of electricity. Other new technologies, such as tablets, PCs, home entertainment systems, and heat pumps, are additional examples. Finally, there are a myriad of new entrants into the industry offering everything from purchase power agreements to funding and revenue and cost sharing for innovative distributed power generation, storage, and efficient end-use technology and programs. These changes have led to a consideration of the evolution to a modern power-delivery infrastructure referred to as the Smart Grid. It is defined by the Energy Independence and Security Act of 2007 (EISA, 2007) as a modernization of the electricity-delivery system. Thus it monitors, protects, and automatically optimizes the operation of its interconnected elements, from the central and distributed generator, through the high-voltage network and distribution system, to industrial users and building automation systems, energy storage installations, and end-use consumers, including their thermostats, electric vehicles, appliances, and other household devices.

Fig. 11.1 illustrates the dilemma these changes will cause for the regulated distribution utility. The study it illustrates was based on the 2012 Annual Energy Outlook (AEO, 2012); it highlights how these changes may impact the demand for electricity leading up to 2035 and was responsible for igniting some of the most active debate among utility executives (Electric Power Research Institute, 2013). In this study the net electricity demand from grid-related services is projected to decrease substantially from energy efficiency and customer generation. This despite projected offsets by new uses of electricity, primarily electric vehicles. Most startling is that since the study was published: (1) energy efficiency has accelerated, (2) new uses have only grown modestly, and (3) customer generation has increased well beyond expectations. The bottom line is a further decline in electricity sales from grid-related services.

These changes, further described in accompanying chapters, in technology and the introduction of new entrants offer the possibility that the grid will be characterized by a two-way flow of electricity and information to create an automated, widely distributed energy-delivery network. The grid will enjoy the benefits of distributed computing and communications to deliver real-time information and to enable the near-instantaneous balance of supply and demand at the device level.

It should be carefully noted that the author does NOT disagree that rapid change is coming with significant implications for the incumbents. What this chapter wishes to explore is whether we need a new business model to deal with these changes.

Utilities should position themselves as the broker for all things electric in the customer’s eyes, “the great rebalancing” described in chapter by MacGill & Smith. The changes now underway will make the marketplace increasingly complex for energy consumers. Without the utility’s intervention, consumers will not be able to successfully deal with a number of actors in the marketplace (Gellings and Gudger, 1997). Collectively these service offerings would satisfy the needs originally identified by The Modern Grid Initiative (2007) (MGI). These also include:

Theoretically these services could continue to be provided by the myriad of firms now in the marketplace, as well as others. However, for society to rely solely on some arbitrary organic growth will not insure that potential benefits of this revolution in technology will be fully realized. These needs are ones that could be provided by enabling electric utilities, in partnership with their regulators, to use existing arrangements to supply new and expanded desirable characteristics using the electric power system in its entirety from consumers to central and distributed resources. As alternative business models are considered, it is important to consider how these needs will be met in those arrangements and compare those potential arrangements to that which leverages today’s regulated business model.¹

It uses these determinations to calculate how much revenue the utility needs to recover expenses. The rate of return regulation became popular during the development of the basic utility infrastructure we have today. It allowed for investors to comfortably provide capital to utilities to build power plants and power-delivery systems in exchange for guarantees against certain competition. For example, during the formation of the industry, this became evident in an arrangement, called the “regulatory compact” in which distribution utilities were franchised or allotted a geographic area in which they became the exclusive provider, provided they agreed to serve all consumers, referred to as an obligation to serve, in return for which they were guaranteed a “fair” rate of return.

There are several inherent advantages to the rate of return regulation. The first is that it is easily sustainable if there is limited competition because prices can easily be adjusted. Second, it provides more comfort to potential investors, as it constrains regulators from enabling too much volatility in price and therefore lowers risk and the cost of capital. In the rate of return regulation, investors can be confident that they have a fair opportunity to receive profit from their investments.

There are, however, four primary disadvantages of the rate of return regulation:

Regulation as applied to public infrastructure in the United States first appeared in the case of railroads. During the 1800s railroads expanded, financed by investors eager to earn a premium return. Understandably their investments were targeted at the most profitable new routes, and prospective customers would be charged sometimes usurious rates. At first, railroads expanded in a rather haphazard fashion with inconsistent prices being charged for the same relative service. Both investors and politicians developed the realization that to best serve the public’s interest, regulation would be needed. Railroad regulation came forward in the 1880s, leading to formation of the National Association of Regulatory Utility Commissioners (NARUC), still active today, and well known for an association that supports regulators, which oversee electric utility regulation. Following the initial regulation of railroads, consumers and utilities themselves began to clamor for regulation of electric utilities.

The rate of return regulation of electric utilities resulted in oversight of prices for electricity and, in turn their capital expenditures, cost of capital, and operating expenditures. In that regard, they must justify and prioritize investments in the infrastructure for electric power generation, transmission, and distribution. To effectively judge the needs of consumers and to best measure utility performance, regulators measure reliability, customer service, power quality, environmental performance, and benchmark expenses as compared to others.

Admittedly, the rate of return regulation is an imperfect scheme, but it works and can easily be molded to accomplish what is needed for an evolving near-perfect power system.

The most substantial nontraditional expenditures are those related to Demand-Side Management (DSM). The most prevalent programs and activities considered to be DSM are: load control; thermal energy storage and dual-fuel heating; innovative rates; energy efficiency; demand response; and electrification (Demand-Side Management, 1984). In these programs and activities, distribution utilities often paid the majority share of expenses, with consumers paying little, if any. In considering future business models, it is not out of the question that this practice could be expanded to investments of communications, information technology, sensors, and the establishment of more complex energy-management systems.

The best DSM examples are energy efficiency and Demand Response. It is now common practice for most utilities to include energy efficiency–type DSM in their portfolios. These are often funded by ratepayer-based programs or other mechanisms to reduce energy consumption, over what it would have been without DSM. Upward trends in energy efficiency program expenditures signal downward pressure on electricity demand. The energy intensity of end uses will reduce further as a result of increased spending by electric utilities on DSM programs and activities. For example, utility spending in the United States and Canada on energy efficiency programs has risen to $9.9 billion in 2014 (Consortium for Energy Efficiency, 2016).

The US Energy Independence and Security Act of 2007 popularized the term Demand Response and generally defined it as including programs and activities that reduce peak demand by the use of dynamic pricing, advanced metering, and enabling technologies. The US Energy Information Administration estimates that over 9 million customers are enrolled in Demand Response Programs ( in 2014), yielding an actual peak demand savings of 12,700 MW. The US Federal Energy Regulatory Commission (FERC) has estimated that the potential for Demand Response is such, so as to reduce peak demand in 2019 by as much as 150 GW (NADRP, 2009).

The concepts of using the utility to fund programs that all utility customers my benefit from, albeit the benefits participants, nonparticipants, and ratepayers at large receive may differ, are very important in considering new business models. We managed to do this very effectively with DSM: why can’t we do it with DER and other service offerings?

As these changes evolve, the best societal option will increasingly be a truly dynamic power system. This approach enables resources and technologies to be deployed operationally to realize all potential benefits. It requires a robust and modern grid characterized by connectivity, rules enabling interconnection, and innovative rate structures that enhance the value of the power system to all consumers. DER, Demand Response, and DSM will be increasingly important in enabling a marriage between these various technologies and systems, so as to enhance the utilization of the power system and enable increased reliability and enhanced consumer choice, while maximizing the penetration of DERs, including PVs, energy storage and efficient buildings, appliances, and devices (Demand-Side Management, 1984).

The Solar Energy Industries Association (SEIA) recently reported that the United States solar market remains what they refer to as “on track” for a record-breaking year, with 1361 MW installed during the third quarter of 2015 and 4.1 GW installed during the first three quarters of 2015. Much of this is new solar power generation installed on residential buildings (www.seia.org). These installations are often funded by third parties and contracted for by consumers through a variety of purchase power agreements. The lowest cost and most effective power system can no longer be configured solely by combinations of central station power generation knitted to customers by power-delivery systems. Today and increasingly into the future, society’s needs for reliable, affordable, and sustainable electricity can best be met by an optimal combination of distributed generation, distributed energy storage, energy efficiency, and new uses of electricity integrated with central generation and bulk system storage.

A more recent report by GTM Research in collaboration with the SEIA reports that a new record was set with the installation of 4.1 GW at an average of 2 MW of solar PV installed per hour through the third quarter of 2016 (GTM Research and SEIA, 2016).

As these distributed solar installations proliferate, the value of DSM will evolve, as will the DSM market participants. DSM incentives targeted toward consumers to influence the pattern and amount of electricity usage will still be valuable, but will change in how they are offered.

Another example is the City of Austin, Texas. In the so called Pecan Street project, Pecan Street Inc., a research and development organization (www.pecanstreet.org) learned through experimentation that the kilowatt-hours generated from homes with west-facing solar panels were more valuable than those generated from homes with south-facing roofs. The energy generated from west-facing panels occurred later in the day when the sun’s arc was westward leaning generating energy that could displace more expensive central generation alternatives. In this example, as DSM evolves, incentives like those for solar energy will need to be tied to the time-varying benefit of load shape changes. If the displaced central generation is more expensive later in the day, then utilities can pay more for the replacement.

Likewise, if the displaced generation is less costly, then the utilities will pay less. As power systems evolve, so will the focus of DSM, but with the same overall objective of maximizing the benefits of electricity to consumers and society. Albeit neither of these examples is of IOUs, they each have their own forms of regulation; SRP has an oversight board and the City of Austin has the city council to deal with.

Any change that derives itself form expansion of distributed technologies can be resolved using the existing regulatory model. The key to enabling necessary changes is for regulators to allow utilities to make investments in DERs, including generation, storage, hyperefficiency tend uses, and the necessary controls and infrastructure to enable their integration with the grid. Fortunately, these concepts are under discussion. For example, in April 2016, Mike Florio, one of the commissioners at the California Public Utilities Commission (CPUC) floated the idea that—perhaps—utilities should be compensated for buying DERs from their customers (California Current, 2016). In its April 8, 2016 issue, California Current reported that: California’s IOUs could get a 3.5% return on power they buy from distributed resources if a proposal by Commission Florio goes forward (EEnergy Informer, 2016).

While many of the details of this proposed approach remain to be resolved, finding a regulatory fix to make DERs an attractive option to IOUs, just as investing in poles and wires currently are, would make sense in this context. A similar regulatory “fix” was conceived and implemented in California to make energy efficiency profitable for IOUs. Why not try the same for DERs?

Admittedly, it is a difficult concept to implement, requiring more regulatory intervention. However, as noted by Baak in his chapter, all indications are that California, at least, is de facto moving in this direction with complicated regulatory proceedings to encourage certain investments for certain cases to achieve the state’s broader desired goals and objectives. So one could argue that this is already happening.

New York, by contrast, appears to want to walk away from micromanaging DERs by drawing lines in who can do what and to whom, while letting the various stakeholders figure out the details further described in the book’s Introduction.

Here are a few examples of how this can be implemented:

The danger may be that the IOUs may abuse their monopoly power if they are allowed to get into the DER business without adequate regulatory oversight. Moreover, the IOUs may also be tempted “gold plate” and “exaggerate” DER investments if proposals, such as those by Mike Florio previously mentioned, are in place. These problems are well known to regulators. The bottom line is that nothing is perfect and some form of regulatory oversight will most likely be required, regardless of which approach is implemented.

Some of the more critical questions regarding TE have been raised by the CA PUC’s Policy and Planning Division, a few of which are listed below(paraphrased) here (Atamturk and Zafar, 2014):

In the spirit of an American folk wisdom saying: “If it ain’t broke, don’t fix it.”, the author examined some of the needs that the power system of the future will provide, as well as its opportunities, and compared them to the tentative promises of TE. Table 11.1 summarizes this comparison.

Understandably many of the attributes of tomorrow’s power system can be met by the existing regulatory model. However, what remains unclear is what the cost and benefits of each model will be and how difficult the transitions may become.

Many of the proposed changes, some of which are described here and in number of other chapters in this volume, could conceivably be adopted and accomplished with the existing regulatory framework, enabling the existing electric distribution utility to become an “Uber Utility” of the future.

An Uber Utility would act as a one-stop shop for consumers, delivering a host of electric energy services they need. It would provide electric energy service along with service and installation of all related electric generation, storage, and energy-efficient devices. Such a utility would be allowed to include all of the assets that could provide overall support to the grid in their rate base. In return, it would retain an exclusive service territory in exchange for providing universal access to all at tariffs, which assure full cost recovery. As noted by Sioshansi in his chapter, the existing grid is a valuable asset already paid for by all. It will most likely remain indispensible to most consumers and most likely even more valuable to prosumers and prosumagers, who will continue to rely on it for reliability, voltage and frequency support, balancing, storage, and backup. For all these reasons, it is incumbent on the regulators to ensure that the integrated grid of the future is adequately funded and maintained by the widest population of possible consumers, prosumeers, and prosumagers, all of whom will continue to benefit from its many valuable services.