In the United States, the modern electric utility industry began to emerge about 100 years ago and would be guided by a philosophy which came to be called the "regulatory compact." Under the compact, state and local governments generally granted utilities the monopoly right to provide electric power in a designated service territory, in exchange for an obligation to serve all electric power customers. Much of the nation's power generation and delivery infrastructure was built and maintained under this arrangement, with customers ultimately paying for the costs of electricity services. State public utility commissions (PUCs) or similar organizations provided oversight of the rates charged for electricity services. PUCs also approved the construction of new power plants and electric power lines, allowing utilities to recover costs of providing service in rates charged to customers. The modern electric utility industry thus emerged and grew in most states as a virtual monopoly, with vertically integrated companies generating electric power, and delivering electricity directly to customers. Large, central station power plants were built employing economies of scale across much of the United States, most often fueled by coal, which was generally an inexpensive, local resource. Large-scale hydropower was developed where it was available as a resource. In areas without access to cheap coal or hydropower, nuclear power later developed as an option for base load power to meet the growing demand for electricity. Natural gas-fired power plants were generally built to meet intermediate and peak load needs. Petroleum saw a brief period of increasing use in the 1970s and 1980s, mostly in dual fuel combustion turbines, but has declined ever since. The vertically integrated, regulated model for the electric power industry remained essentially unchanged across the United States until the latter years of the last century. The Public Utility Regulatory Policies Act of 1978 (PURPA) ( P.L. 95-617 ) was arguably the law that ended the near utility monopoly on electric power. Among other goals, PURPA was designed to conserve supplies of natural gas (considered threatened at the time), encouraging fuel efficient cogeneration and alternative fuels and methods to generate electricity. PURPA required electric utilities to purchase power from these new power generators, essentially allowing a competitive provider into a utility's formerly exclusive service territory. The efficiency of combustion turbines used for generating electricity accelerated as their use in PURPA-qualified cogeneration projects expanded, and this in turn aided in the growth of the nonutility power sector. The power generation sector has a variety of structures and ownership arrangements. Electric utilities have diversified ownership, including publicly owned utilities, investor-owned utilities, electric cooperatives, federal power agencies, and nonutility generators. Competition in the electricity industry was strengthened as federal policy with the passage of the Energy Policy Act of 1992 (EPACT92; P.L. 102-486 ), allowing a new class of nonutility producers to emerge. As is shown in Figure 1 , the nonutility power generation sector is the largest in the United States. In the early years of the last century, electric utility companies quickly realized that they could reduce costs and enhance reliability by interconnecting with one another, thus sharing generation resources. The development of "power pools" allowed member electric utilities to exchange power, or transfer (i.e., "wheel") power to another utility in either wholesale or retail (to an end-use customer) transactions. Power pools can be "loose" or "tight," with the level of independence being the primary differentiator. With FERC Order 2000, the transformation of existing tight power pools was completed with the formal establishment of the Regional Transmission Organizations (RTOs) in several regions of the United States (see Figure 2 ). This led to the rise of wholesale power markets, and enabled industry restructuring in various U.S. states and regions, requiring utilities in some states to move power plants into a competitive function, while retail distribution utilities remained under state regulation. Under this arrangement, utility transmission systems are run by the RTO and are regulated largely under FERC jurisdiction. In some states, retail competition was introduced to give end-use electricity consumers a choice between their incumbent utility supplier and competitive electricity suppliers. Power plants under this new regime were therefore required to compete with each other to sell power to retail distribution companies in markets administered by the RTO. Nowadays, the electric utility model is under further pressure as the sector deals with issues such as the aging of power generation and other assets, the implementation of new environmental regulations leading to different choices in power generation fuels, and the development of technologies providing more and newer options for customers to self-generate electric power. These factors have the potential to cause dramatic changes in how the United States acquires, generates, and uses electricity. Given that the United States seems to be at a turning point in the history of the electric power sector, some have advocated for the electric utility industry model to be reinvented under a "Utility 2.0" paradigm, wherein the projected needs of society for electric power and services become the driving force behind future utility investments. Various states and jurisdictions have begun initiatives to look at what this new "regulatory compact" could specifically encompass. The State of Maryland, for example, has issued a report detailing its "vision of an energy future that is more reliable, cost effective, green, energy efficient, consumer-directed, and technology advanced. Utility 2.0 can make this service quality transformation a reality with major economic, environmental and security benefits to Maryland and all its citizens." Another proposed model for Utility 2.0 in the State of New York would see development of a system capable of accommodating more renewable electricity from smaller solar and wind generation, and depend less on power from larger, central station power plants. The question some stakeholders are asking is whether a formal transition from today's grid to the grid of the future is needed. This report will begin to explore the issues, discussing what forms a transition could take, and suggest questions that Congress may want to address. Electricity is fundamental to the commerce and daily functioning of the U.S. economy. The modern, technological underpinning of manufacturing and services relies largely on digital devices which have increased U.S. productivity and global sales. The way electricity is produced has changed in the last 40 years, along with the regulatory structures and laws governing its production in most of the United States. The following sections will discuss some of the primary factors affecting the U.S. power sector. For many years, the growth in sales of electric power could be directly related to growth in the economy. However, with energy efficiency in homes and appliances increasing, a decoupling of growth in electricity demand from growth in Gross Domestic Product (GDP) is occurring. According to the U.S. Energy Information Administration (EIA), the linkage has been declining over the last 60 years, as U.S. economic growth is outpacing growth in electricity use. The trend is illustrated by Figure 3 , which shows growth in electricity use and growth in GDP over the period. EIA's projections point to a continued decline in electricity use relative to economic growth. While there may be years of relative growth in the future, EIA does not expect a "sustained return to the situation between 1975 and 1995, when the two growth measures were nearly equal in value, or the earlier period in which the growth rate in electricity use far exceeded the rate of economic growth." EIA attributes several factors as drivers to this trend, including "slowing population growth, market saturation of major electricity-using appliances, improving efficiency of several equipment and appliance types in response to standards and technological change, and a shift in the economy toward less energy intensive industry." With growth in demand for electricity having been essentially flat for many years, the need for new power plants has been delayed in many parts of the country. The projections for future demand growth in most regions of the United States are even declining. However, even an annual growth rate of 0.9% can mean an increase in electricity demand of 27% over the next 30 years, and may result in a need for new power plant capacity. With the passage of the Clean Air Act (CAA) amendments in 1970, Congress required the Environmental Protection Agency (EPA) to establish standards to reduce the potential health and environmental impacts of fossil fuel use by limiting emissions by-products or other consequences of combustion processes. These environmental regulatory requirements have been evolving in the last decade due to various legal challenges to the regulatory implementation of federal laws. Much industry attention has focused recently on the pending finalization of some of these regulations, and their potential to contribute to retirement decisions for some coal-burning power plants. In addition to being the largest source of electric power, coal-fired power plants are among the largest sources of air pollution in the United States. Under the CAA, however, they have not necessarily been subject to stringent requirements: Emissions and the required control equipment can vary depending on the location of the plant, when it was constructed, whether it has undergone major modifications, and the specific type of fuel it burns, among other factors. More than half a dozen separate CAA programs could potentially be used to control emissions, which makes compliance strategy potentially complicated for utilities and difficult for regulators. While the new rules have been developed at the federal level, by EPA, they will generally be implemented by state agencies. They include the Cross-State Air Pollution Rule (which replaced the Clean Air Interstate Rule); the Mercury and Air Toxics Standard, or MATS rule; the rule for coal combustion residues; and the Clean Water Act Section 316(b) guidelines for once-through cooling water systems. The MATS rule requires coal-fired power plants larger than 25 megawatts (MW) in capacity to incorporate the maximum achievable control technologies (MACT) by April 2015 needed to reduce the airborne emissions of mercury, acid gases, and toxic metals. However, state environmental permitting agencies are allowed to grant a one-year compliance extension. At the end of 2012, according to EIA, there were 1,308 coal-fired generating units in the United States, totaling 310 gigawatts (GW) of capacity, and approximately 71% of U.S. coal-fired generating capacity has installed (or plans to install) environmental control equipment to comply with MATS. With low natural gas prices depressing electricity market prices and slow growth in electricity demand, the MATS rule adds to the economic pressure on coal plants. EIA currently expects that a total of 60 GW of coal capacity will retire by 2020, with 90% of these retirements taking place by 2016 "coinciding with the first year of enforcement for the Mercury and Air Toxics Standards." Regulations under development at EPA would impose new requirements on power plants to control greenhouse gas (GHG) emissions. In September 2013, EPA proposed standards for the control of carbon dioxide (CO 2 ) emissions from new electric generating units burning fossil fuels. EPA suggested that utilization of carbon capture and storage (CCS) is a viable means for new coal-fired power plants to comply with the proposed standards. As requirements for new sources (i.e., new power plants), EPA's proposed standards do not directly apply to existing power plants currently producing electricity. EPA's regulations to reduce GHG emissions from existing power plants were finalized in October 2015. Since carbon dioxide (CO 2 ) from fossil fuel combustion is the largest source of U.S. GHG emissions, and fossil fuels are used for the majority of electric power generation, reducing CO 2 emissions from power plants plays a key role in the Administration's climate change policy. Under the provisions of the Clean Power Plan (CPP), states must prepare plans that reduce either total CO 2 emissions or emission rates at affected EGUs. When implemented, EPA projects the state plans will reduce CO 2 emissions from U.S. power generation approximately 32% by 2030 compared to 2005 levels. EPA projects that implementation of the CPP may result in renewable energy (hydro and non-hydro) making up 28% of total generating capacity (as compared to its base case projection of 25% renewables). This could result in renewables representing 20% of total electricity generation in 2030, as compared to 18% in EPA's base case projection. As of 2012, coal-fired power plants are the single largest source of U.S. electricity generation (see Figure 4 ). EPA is also proposing to regulate the management of coal combustion residuals (CCR) in landfills and surface impoundments, under its authorities in the Solid Waste Disposal Act (42 U.S.C. §6901 et seq.); and to revise effluent limitations guidelines (ELG) for power plant wastewater, under its authorities in the Clean Water Act (33 U.S.C. §1251 et seq.). Each proposal is intended to reduce the amount of metals and other pollutants released to the environment from coal-fired power plants. Since each proposal would regulate surface impoundment ponds, EPA has stated that its final decision on the CCR rule may be aligned with any final requirements adopted under the final ELGs. A final CCR rule is expected to be issued in December 2014; the final ELG was issued in September 2015. All power plants are subject to retirement when they reach the end of their useful service life (i.e., how long the property will be useful to the enterprise). The average age of U.S. power plants is now over 30 years, and the life expectancy of most power plants is about 40 years. As with electric power plants, electric transmission and distribution system components are also aging, with power transformers averaging over 40 years of age, and 70% of transmission lines being 25 years or older. In areas of the country with traditional ratemaking (as opposed to areas with competitive markets), electric utilities recover the cost of building and operating a power plant (and other related infrastructure) from ratepayers as depreciation expense under the "cost of service" model. Electric utility power plant costs are typically collected from ratepayers over a period of about 40 years, which is considered the average service life for a power plant. Thus, the original cost of many older plants has already been recovered in rates, while the cost of younger power plants is still being recovered. While older power plants are usually well-maintained, they are generally not as efficient as newer power plants. The costs of modernizing older coal-fired power plants to meet new regulatory requirements can be relatively high. When the cost of upgrades to meet new environmental requirements is considered along with perhaps increasing operations and maintenance (O&M) expenses, many older coal power plants are likely to face outright retirement decisions. Electric utilities are looking at increasing costs to replace aging power plants and other infrastructure. The electric utility industry has always been capital intensive, requiring significant construction investment to produce and distribute power. Today's increased costs of construction are being driven by higher materials costs, as the prices of raw materials have been climbing, and the cost of manufactured components has also risen. Costs of maintaining and modernizing coal-fired plants (in particular) are also increasing due to environmental requirements, and altogether new concerns such as cybersecurity. With limited new generation construction and difficult prospects at state public service commissions for increased electricity rates, the opportunities for utilities to earn higher returns on investment have come in recent years from unregulated markets or in new transmission with approved higher return-on-equity incentives. However, with current low natural gas prices, revenues from electricity markets have been declining. With falling or static electricity demand and sales, control of costs is becoming a key focus in maintaining levels of returns on investment, and dividends to shareholders for investor-owned utilities. Utilities are increasingly looking at minimizing operations and maintenance costs, and downsizing workforces even as they face impending retirements of a whole generation of workers. The U.S. electric utility industry as it exists today largely reflects the underlying fuel resources, economics, and physical limitations which exist in various regions of the country. These characteristics led to the specific technologies and infrastructure used to produce electricity. The regulatory regime has changed in some parts of the United States from a cost-of-service approach to a competitive environment for power generating plants. With the increasing availability of new technologies and paradigms for satisfying electricity demand, the traditional ways of doing things in the electric utility business are being challenged. How some of these factors have and are expected to drive change is discussed in the following paragraphs. While the formative role of the regulatory compact has diminished in some parts of the country, federal and state public policy goals and requirements still have a substantial effect on the operations and investment decisions of electric utilities. Many regard PURPA as the first instance of federal legislation bringing change to the traditional model of electric utility industry. By essentially allowing nonutility entities to generate and sell power for resale to end-users, PURPA brought competition to the industry. This new paradigm was expanded upon by EPACT92, which formally created a class of competitive power producers designated as "electric wholesale generators." Congress recognized in these legislative actions that entities other than electric utilities were capable of generating electric power efficiently and cost-effectively. State governments have been very active over the last two decades enacting policies mandating various levels of renewable electricity generation in various Renewable Portfolio Standard (RPS) requirements or goals for renewable electricity development. When combined with such state programs, the availability of federal tax incentives has led to a proliferation of utility-scale projects using wind power and solar photovoltaic (PV), spurring growth especially for solar PV in the commercial and residential sectors. EPA's regulations under the CAA are further examples of public policy mandates. The requirements of compliance and potential impacts of EPA regulations on power plant operations are discussed earlier in this report. Distributed Generation (DG) is the term used to describe electric power generated at or near the point of consumption (i.e., the customer or load). DG thus differs from base load power plants (mostly coal and nuclear power units) which were designed for economies of scale, and located usually at some distance from where the electricity is consumed. DG includes traditional backup power sources (such as the large gas-powered generators used by institutions and companies), combined heat and power facilities (used for industrial, district, and community power generation ), and renewable electricity power systems used by some businesses and residences. Many manufacturers and institutional users have traditionally generated on-site some or all of the electricity they consume, while others maintain diesel or oil generation for emergency backup purposes when power outages occur. DG technologies are also referred to as distributed energy resources (DER). Residential scale applications of renewable electricity technologies have seen growth in the last few years with the drop in the prices of solar PV panels, and the growth in "solar roofs" aided by state and federal tax incentives, grants, and net metering provisions. New designs for wind power units optimized for "urban" environments are being developed, and may find increased opportunities for deployment. The end-use application would dictate the specific DG technology choice, as technologies suitable for base load would not be necessarily suitable for power quality or combined heat and power (CHP) or even trigeneration uses. Nevertheless, most residential applications of DG in the United States are rooftop solar PV. As of 2011, 4 GW of distributed solar PV capacity had been installed in the United States. Estimates are that distributed solar PV capacity could reach 20 GW by 2017, with total solar PV penetration increasing to perhaps 50 GW by 2020. However, this would still represent only a small part of overall U.S. electricity generation. The U.S. grid had a generation capacity of 966 GW in 2013. With the relatively new abundance of natural gas produced from unconventional resources has come an expectation of continued lower prices for natural gas, at least over the near term. Decreased natural gas prices are lowering wholesale electricity prices, stimulating a major switch from coal to gas-burning facilities. However, overall electricity costs are still increasing in many regions of the country, and prices for electricity are expected to rise. This may open a window of opportunity for increased development of residentially-sized combined heat and power units, assuming fuel cell and microturbine applications become more cost-competitive and thus attractive to consumers. Large fuel cell installations are already being used to provide power to data center owners who value a greater level of power quality and reliability than they believe they can get from traditional utility service. The advent of new, smaller scale but higher efficiency power generation technologies could possibly change how consumers obtain the majority or all of their electricity and energy needs, and may have the greatest potential for impact on the utility model. A growing amount of electric power is being generated by natural gas, and a convergence of electric power and natural gas utilities may eventually result in a new, customer-focused energy industry focused on providing consumer services. A microgrid may be defined as "any collection of interconnected loads and distributed energy resources (i.e., distributed generation) within clearly defined electrical boundaries that can be controlled as a single entity and that can operate in both grid-connected or island mode (i.e., non-grid connected)." Thus, power is generated and consumed in a localized distribution system. Many colleges and universities use microgrids because they can choose the power generation technology (for example, natural gas-fueled or renewable), manage energy costs, and have control over how the system is operated (i.e., as combined heat and power, or as power generation sources only). The ability of microgrids to continue operations as a "power island" appeals to the U.S. Department of Defense. The agency has installed a few pilot microgrid projects with renewable electricity and energy storage to test the economics, resilience, and operational independence in the event of a large scale power outage. Most microgrids are expected to continue to be grid-connected and only operate in "island" mode when the costs or circumstances necessitate. While the decision to adopt microgrids may be based on the desire to reduce energy costs, microgrids are not necessarily cheap to build or operate, especially for the colleges or small communities seen as projected civilian customers. For example, in 2012, the San Diego Gas and Electric Company (an electric utility) started building a microgrid in Borrego Springs, CA, with a grant of $7.5 million from the U.S. Department of Energy and $2.8 million from the California Energy Commission. The project was estimated to cost at least $12 million, and sought to integrate multiple DG technologies using advanced distribution and control technologies. Some recent catastrophic events have indicated to observers the vulnerabilities of the greater grid. For example, with the prolonged power outages resulting from Hurricane Sandy in 2012, much attention was focused on electric system resiliency and the potential for microgrids to aid in storm recovery efforts. Those who were served by microgrids were able generally to ride out the storm with virtually no loss of power as they were not dependent on the grid for electricity. In the wake of the Sandy power outages, some states were considering microgrids to provide support for police, fire, hospital, and operations centers for emergency workers in a widespread power outage as they restore damaged distribution and transmission systems. The great promise of energy efficiency is a reduced need for electricity, which can mean a decreased need for power plants to generate electricity and thus less fuel consumption. Since most of the power we use comes from the combustion of fossil fuels, reduced electric generation translates into fewer emissions into the air, and less water consumed in the process of steam production. Many people are looking to cleaner energy sources as a solution. However, even "clean" energy sources can have their drawbacks. Wind and solar farms can impact birds or other animal habitats, and conventional nuclear power requires the mining and processing of uranium, with disposal of spent nuclear fuel requiring secure, long-term storage due to radioactivity and nonproliferation concerns. According to EIA, the average U.S. household consumed 11,320 kiloWatt-hours (kWh) of electricity in 2009. Historically, the greatest consumption of electricity in U.S. residences has been for heating and cooling purposes, but standards for energy efficiency have considerably reduced the amount of power used by these systems. However, a new trend has emerged recently with the energy savings achieved by these appliances being almost offset by a growing number of consumer devices in the home which are using more electricity. As a result, EIA is now reporting that the largest portion of power consumption in homes is for appliances, electronics, lighting, and other miscellaneous uses. Research aimed at increasing energy efficiency continues, funded by a mix of federal and state programs. Approximately 27 states have established mandates for utility companies with energy efficiency resource standards or goals. These efforts are expected to result in energy savings between now and 2025 which may offset any demand growth in the period. These new energy efficiency programs are likely to focus on the appliances themselves as a new wave of appliances with built-in intelligence becomes available. These "Smart Appliances" may be controlled by a home-based system which will automatically cycle or run appliances at the best times to reduce energy usage and costs. Such systems may be initiated or augmented by smartphone applications and other devices which will automatically adapt household energy use according to residents' usage patterns. Residential energy management will likely take a major step forward with the design and construction of Zero Net Energy Homes, which the U.S. Department of Energy describes as "high performance homes which are so energy efficient, that a renewable energy system can offset all or most of its annual energy consumption." Thus, a zero net cost for energy can result as sales of electricity generated on-site from renewable energy balance costs of energy purchased. Such systems may also be applicable to new commercial buildings, perhaps further decreasing demand for utility-generated electricity. One area with the potential for increased electricity consumption is transportation. A growing number of automobile manufacturers are introducing plug-in electric vehicles (EVs) as new products for U.S. consumers. Some utilities are considering whether EVs will be a longer term means for addressing increasing electricity demand, and provide opportunities for vehicle-to-grid energy storage and related services. When parked, vehicles could potentially provide various grid services. Charging of EVs can potentially be controlled and can provide a source of dispatchable demand and demand response. Controlled charging can be timed to periods of greatest [variable renewable generation] output, while charging rates can be controlled to provide contingency reserves or frequency regulation reserves. Vehicle-to-grid (V2G) (where EVs can partially discharge stored energy to the grid) may provide additional value by acting as a distributed source of energy storage. Most proposals for V2G focus on short-term response services such as frequency regulation and contingency. Their ability to provide energy services is more limited by both the storage capacity of the battery and the high cost of battery cycling. This could restrict their ability to provide time shifting (energy arbitrage) beyond their ability to perform controlled charging. The role of V2G is an active area of research. Because electric vehicles in any form have yet to achieve significant market penetration, assessing their potential as a source of grid flexibility is difficult. However, analysis has demonstrated potential system benefits of both controlled charging and V2G. However, obstacles exist to the wider adoption of EVs. Along with high cost, the limited range for EV travel is also described as one of the current barriers for large scale EV penetration in the U.S. market. Building out a national infrastructure for EV charging might address this concern. While this would seem to represent an opportunity for electric utilities, it is possible that some other entity would build this EV charging network. Regulatory issues have also been raised as regards the sale of electricity from private owners of EV charging stations (including the question of whether a sale of electricity from an EV charging station is a "sale for resale," and as such, subject to laws governing electric utilities). Some state jurisdictions have moved to prevent classification of EV charging stations as electric utilities. A recent United Nations study predicted the possibility for an almost complete transition of U.S. automobiles from internal combustion engines to EVs by 2050, should that be a policy goal. The potential of such a scenario for large scale GHG reduction would depend on how electricity is generated, i.e., assuming that U.S. policy is focused on almost exclusive use of low or zero-carbon fuels and sources. Fuel cell vehicles could present a competitive or alternative pathway to a potential transportation future dominated by EVs. However, EIA projects that EVs and plug-in hybrid vehicles together may achieve only a 2% penetration of the light-duty vehicle market by 2040. EVs currently represent almost 1% of light-duty vehicle sales. Today, electricity must be generated throughout the day and night at levels needed to meet varying demand because energy storage applications are very limited. While batteries, compressed air, and pumped hydro storage schemes are currently in use, they represent a very small part of the overall power generation portfolio due mostly to cost and efficiency issues, and suitability of siting for new pumped hydro projects. Increased use of energy storage could benefit consumers because levels of power generation could be reduced, as would the real dollar and environmental costs of generation. Innovative technologies and schemes for energy storage are being tested, with the possibility that newer, more economic means of large scale energy storage may soon become available. Economies of scale for advanced battery production are also possible, resulting in cheaper, more effective storage options. Increased energy storage would also benefit the deployment and efficiency of intermittent and variable renewable technologies, since surplus energy could be stored and used when needed. These resources could then potentially provide power during times of peak demand, and could help to address load and demand balancing issues raised with increasing amounts of renewable electricity generation on the grid. California offers an example of how storage can help integrate renewable generation. The state has ambitious plans for renewable generation, with a 33% RPS requirement by 2020. The California "duck curve" presents a scenario for a grid whose operations may be substantially affected by renewable resource integration, since peak renewable generation from wind and solar power is unlikely to coincide with customer demand (see Figure 5 ). In the period from 2015 to 2020, the California Independent System Operator (CAISO) expects increasing amounts of solar power generation due to RPS requirements. The deepening trough in the chart from 2015 to 2020 (from the early morning to the afternoon hours) represents the net load as more solar power comes on the system. Customer demand during the daytime for electricity will not match the power being generated by solar resources, and CAISO may be required to shut down traditional base load generation resources to avoid damage to the system from potential over-generation. But as the sun begins to set solar generation ebbs, and traditional base load fossil must ramp up quickly to meet demand. Most existing base loads power plants are not designed to cycle up and down quickly in this manner. As a result, California may need more fast-ramping natural gas power plants to meet this new base load need (or energy storage) in order to match the variability of renewable generation. Large scale energy storage could help electric utilities to manage costs, especially as a dynamic source of energy or as a demand-side resource. But determining appropriate pricing strategies for energy storage will be important as a driver of stand-alone energy storage projects. Electric utilities have fought past regulations requiring avoided cost payments, and the industry will likely want to ensure that it is not providing energy at a lower rate to storage developers, and purchasing energy back at higher rates. The preceding sections have discussed some of the new drivers for technology in the power sector. While the electric utility industry has also seen technological advances over the years, the economies of scale possible with large, central station power generation have discouraged any real change in the industry model. But with aging of this power generation infrastructure, new environmental regulations, the prospect of increased supplies of natural gas for years to come, and the potential development of economic alternative power technologies, electric utilities are facing questions about the near-term future. This section of the report will discuss how change may come to the electric utility industry, and the roles that government may possibly play. Electric utilities are the incumbent power provider today, with an investment in infrastructure and primary access to customer bases in most of the United States. The PUCs are accustomed to working with utilities on ratemaking, plant location and transmission siting, and planning for the future with integrated resource planning. Given the regional nature of the grid and the different regulatory regimes and infrastructures which exist, it may be reasonable to think that the current system is too entrenched to change. Nonetheless, the electric utility industry seems to be fully aware of the potential for change. The question is whether and how much the industry will embrace new technologies and market opportunities. Some companies may see DG as appealing to only a small number of customers, but in times of shrinking revenues, any real reduction of the customer base can be significant for some companies. Nonetheless, the perceived trend towards DG technologies is forcing many utilities to look at how they are positioned in the electricity business. Some companies are opting out of the merchant power generation and electricity marketing segments, choosing to focus on traditional electricity service to customers. Other companies are looking at how they can embrace renewable generation as their customers demand more clean energy solutions. The Edison Electric Institute (EEI) contemplates that the potential rise in DG could be a threat to the regulatory paradigm that allows costs of service to be recovered from the consumers who benefit from the investment (as discussed in the next section). EEI has cited examples from other industries (i.e., the telecommunications and the airline industries) which faced changes in their regulatory and competitive environments, and proposes changes in state regulatory policies to address the issue. The evolution to some version of a future Utility 2.0 model will not be without costs. But the electric utility industry is concerned about its ability to recover the costs of its current plant in service (i.e., Utility 1.0 ), as it looks at a new era of infrastructure building and costs looming ahead. In particular, the electric utility industry has raised specific concerns with state programs for net metering, especially in areas with growing penetration of residential solar PV installations. Net metering is one of several "states must consider" standards added to PURPA by the Energy Policy Act of 2005 (EPACT05; P.L. 109-58 ). Under Section 1251 of EPACT05, electric utilities were called upon to make net metering available as a service to customers wishing to generate at least a portion of their own electricity needs. Ostensibly, state net metering programs are intended to encourage DG adoption. Net metering requirements are intended to compensate consumers for specific types of self-generation identified by states, or to promote self-generation. For electric customers who generate their own electricity, net metering allows for the flow of electricity both to and from the customer—typically through a single, bi-directional meter. In some instances, during times when a customer's generation exceeds the customer's on-site use, electricity from the customer flows back to the grid, offsetting electricity consumed by the customer at a different time. In other instances, the customer is paid for power generated at either the utility's full retail rate or at the utility's avoided cost price. Utilities have expressed concerns that their current investment in power generation infrastructure to serve today's customers may not be fully recovered if growing numbers of these customers opt for distributed generation. The threat to the centralized utility service model is likely to come from new technologies or customer behavioral changes that reduce load. Any recovery paradigms that force cost of service to be spread over fewer units of sales (i.e., kilowatt-hours or kWh) enhance the ongoing competitive threat of disruptive alternatives. While the cost recovery challenges of lost load can be partially addressed by revising tariff structures (such as a fixed charge or demand charge service component), there is often significant opposition to these recovery structures in order to encourage the utilization of new technologies and to promote customer behavior change. The argument is then made that under such policies, those customers who do not switch to distributed energy resources will be left to pay the unrecovered costs of existing central station infrastructure. Thus, in effect, legacy customers may make it easier for DG customers to "exit the system" with the resulting cross-customer subsidy, and "stranded cost" exposure for utilities. While the regulatory process is expected to allow for recovery of lost revenues in future rate cases, tariff structures in most states call for non-DER customers to pay for (or absorb) lost revenues. As DER penetration increases, this is a cost-recovery structure that will lead to political pressure to undo these cross subsidies and may result in utility stranded cost exposure. These legacy customers, some argue, are likely to be less affluent residential customers, or other customers who are not able to or are less inclined to switch to DG systems. Thus, some electric utilities argue that state policies should consider utility system cost recovery in the regulatory schemes for net metering. However, the Center for American Progress (CAP) debates the viewpoint that mostly "affluent" customers are adopting DG systems, and shows adoption of rooftop solar photovoltaic (PV) systems by middle-income customers. The question is: Who is buying up all of those solar power systems? Through our analysis of solar installation data from Arizona, California, and New Jersey, we found that these installations are overwhelmingly occurring in middle-class neighborhoods that have median incomes ranging from $40,000 to $90,000. The areas that experienced the most growth from 2011 to 2012 had median incomes ranging from $40,000 to $50,000 in both Arizona and California and $30,000 to $40,000 in New Jersey. Additionally, the distribution of solar installations in these states aligns closely with the population distribution across income levels.... In this issue brief, we show that rooftop solar is not just being adopted by the wealthy; it is, in fact, mostly being deployed in neighborhoods where median income ranges from $40,000 to $90,000. CAP's analysis is based on solar PV installations, which are largely being installed in states with good solar resources or with favorable state incentive policies. Some observers look at the EPA's regulations for carbon emissions from new power plants and proposed reductions of GHGs from existing power plants and contend a transition of the electric power sector is already underway. EPA's existing or proposed rules do not mandate anything with regard to utility industry structure; but EPA's regulations for GHG reduction between now and 2030 may lead utilities to the use of more natural gas generation, and renewable electricity, and less coal-fired generation. EPA's GHG regulations are focused on larger scale, central station generation of electricity. Wider use of natural gas by central station generators and DG applications may hinder GHG reduction goals, since natural gas is a fossil fuel. Therefore, if even lower carbon emissions or a GHG emissions-free regime is the future of electricity generation, then what fuel or paradigm is this future to be based on? Separation and sequestration (or reuse) of carbon captured from fossil fuels may be economical at that time. Renewable electricity generation may be another long-term answer, but the United States is far from a grid which could depend mainly on renewable generation from solar and wind power without at least some central station generation (possibly nuclear power), and large scale energy storage. Increased use of natural gas has been described by some observers as only a "transition strategy" to a clean energy future. If natural gas is a transitional fuel strategy, then could hydrogen be its replacement? Coal and natural gas could well be sources of hydrogen (assuming carbon capture and reuse or sequestration), as might nuclear power or renewable electricity (if electrolysis of water is a source). And hydrogen is also a fuel which could be used by fuel cells which may also be a significant residential energy choice for DG in the future. It is important to note that approximately one-third of today's approximately 100 U.S. nuclear power plants in service will see their operating licenses expire by 2030. A number of these plants may face retirement, as issues of competitiveness in a time of low wholesale electricity prices and the costs of keeping these aging plants running are taken into consideration. At this time, only five new nuclear reactors are under construction in the United States. To some, these and other questions may point to the need for a longer-term national or regional energy policy planning if we are to know how the U.S. energy future will be structured to promote lower GHG emissions and/or higher renewable energy use. Assuming that GHG reduction is the direction of future U.S. energy and environmental policy, a formal transition requiring federal policy guidance for the electric utility industry may be an option if, for example, the energy markets fail to transition smoothly to such a clean power future. Market failures of this sort have been discussed by industry observers in the past, with stranded assets and company bankruptcies posited as potential disruptions. While it is unlikely that such instances would result in a major disruption of the nation's power supply, the effect on financial markets of a major company failure could be a concern. Similar transitions have been accomplished in the past by other industries without significant congressional policy intervention. The telecommunications industry dealt with competitive market issues from deregulation in the early 1990s, resulting in companies like AT&T taking a $6.7 billion write-down to modernize its plant in preparing for competition. As stated earlier in this report, electric utilities are already looking at cost control strategies as growth in demand for electricity declines. Changing the remaining life of assets in book depreciation rates authorized by state utility commissions is a tool that can be used to deal with stranded assets. This would allow utilities to accelerate recovery of the cost of their assets if they believe cost recovery over longer service lives is threatened. ... the Uniform System of Accounts [as per 18 C.F.R. Part 352 under the Code of Federal Regulations], defines depreciation as the loss in service value not restored by current maintenance incurred as a result of consumption or prospective retirement of (utility) plant in the course of service from causes that are known to be in operation and against which the utility is not protected by insurance. Among the causes given consideration are wear and tear, decay, obsolescence, changes in the art, changes in demand, and requirements of public authorities. Concerns over rate base erosion from net metering policies and a growth in distributed generation are issues related to the competitive environment (i.e., changes in demand, related to the requirements of public authorities). A potential switch to DER involves all customer rate classes—from residential to commercial to industrial electricity consumers. This is due to competition for the electricity customer, as technology and other changes to the business and regulatory environment present customers with choices. Recovery of costs through increased depreciation rates has been recognized by EEI as a proposed action to help electric utilities deal with potential competition from DER. However, such issues are largely under state jurisdiction. If a change in the depreciable service life is made, then making this change as early as possible is preferable since this will result in a smaller increase in overall customer rates. The shift to a new, shorter remaining service life recovery would raise the depreciation portion of customer rates but it would be potentially spread over a larger customer base. The U.S. grid has long been considered as one of the wonders of the last century. But the grid is aging and in need of modernization in many areas. The average age of U.S. coal power plants, the mainstay of the industry is about 43 years, and supporting transmission and distribution systems are similarly aging. New technologies and cost structures are now making inroads into U.S. electricity markets and may eventually result in dramatic changes to the industry over the next few decades. Many consumers have real choices in how to obtain the power they use today depending on availability and cost, and will have greater choices in the future as technologies currently under development reach the market. With renewable electricity, fuel cells, and EVs seeing increasing acceptance by consumers, regulations like RPS requirements, net metering, and tax incentives are making adoption of individualized power generation solutions easier. As the grid modernizes, it will likely be expanded in ways as to be flexible enough to accommodate both new technologies and the ways customers will want to use power. A more flexible grid is also seen as a key to incorporating more renewable generation with a greater degree of intermittent or variable loads. Regulators will be challenged to recognize and plan for the possibilities of change, with its potential costs and implications for electricity industry structures. However, economic development at the national and local levels will likely continue to be tied to the availability of low cost energy for many years to come, and the electric utility model has proven that it can provide relatively low cost electricity. Therefore, it is possible that the majority of today's consumers will remain future utility customers if the grid's infrastructure can be modernized and grid electricity costs can be kept at reasonable levels. If not, then some customers who can afford to switch may switch to DG solutions. Such systems may even add to resiliency as smaller systems may be inherently more reliable than a transmission-to-distribution model as the focus is on smaller service areas, and thus can minimize large-scale outages. Telephone companies recognized that change was coming and adapted to change as they became "telecommunications" companies, offering choices that ranged from "plain old telephone service" to a variety of networked and other services. The telecommunications marketplace expanded with the range of technological offerings. The analog for evolving electric utilities may begin with an offering of "plain old electricity" service in recognition of what services customers may be willing to pay for. Continuing the telecommunications comparison further, the build-out of the system from plain old telephone wires to cellular and fiber optic infrastructure was accomplished by serving the needs of consumers. The cost of the infrastructure build-out was underwritten by customers willing to pay for the perceived added value of these new services. For the electric utility industry, the "Smart Grid" may eventually be the great enabler of change. While some look upon the Smart Grid as a gradual modernization of the system to include two-way intelligence capabilities for monitoring and controlling systems, others see its potential for enabling services and even greater change. Most electric utilities appear to view the intelligence and communications capabilities of Smart Grid systems positively, even with the added concerns for cybersecurity. Cost of operations could potentially be reduced and system resiliency improved from further integration of automated switches and sensors, even considering the cost of a more cybersecure environment. But with the potentially high costs of a formal transition, some see the deployment of the Smart Grid continuing much the same as it has, with a gradual modernization of the system as older components are replaced. The potential for the Smart Grid to enable change may be exemplified in the potential to further integrate variable renewable resources at a lower cost. A wider deployment of a "fully-functional" Smart Grid could see the renewable generation in one state or region supporting renewable generation in another state or region, with the power flowing from where it's generated to where and when it would be needed. It is likely that all of the drivers and technologies discussed earlier—from microgrids, energy efficiency, smart appliances, and zero-net energy homes to EVs and energy storage—could all see more effective deployment at lower cost from an integrated Smart Grid approach. However, the cost of a build-out of a more fully functional Smart Grid could be compared against the cost of building a new, more flexible natural gas-based generation system to replace retiring coal (and perhaps retiring nuclear) capacity, and to augment renewable power in a load-following (i.e., backup for variable renewable generation) mode. Modernization of the grid has been accomplished to various degrees as new digital systems replace old analog components. Attempts to introduce some components of the Smart Grid have been deemed successful (i.e., the deployment of synchrophasors providing real-time information on system power conditions, and the replacement of old inverters on solar PV systems with smart inverters capable of disconnecting from the grid during times of power interruption ). But introduction of other components have been problematic. Smart Meters have run into cost and performance issues and resistance to the technology (generally from concerns of some customers over potential health impacts of radio wave emissions), causing some to question if the Smart Grid will really provide the expected benefits. Congress has enacted legislation several times in the last 10 years in recognizing the role of new electricity technologies and their potential to change how consumers use electricity. The vehicle for implementing legislation has often been "states-must-consider" standards added to PURPA. As such, state utility regulators "must consider" the proposed action, and decide whether or not to adopt the standard as a requirement for the electric utilities it regulates. EPACT05 added five states-must-consider standards requiring states to consider provisions such as net metering, a consumer option for smart meters, and time-of-use pricing. The Energy Independence and Security Act of 2007 ( P.L. 110-140 , EISA) also added several states-must-consider standards including a provision for Smart Grid investments. As regards previous states-must-consider standards, responses have varied depending on state policies. Some states adopted the proposal, while other states have said that their own policies have gone beyond the requirement and have thus declined to adopt the federal initiative. Still other states have considered the initiative and declined to adopt or adapt the initiative, but in so doing appear to have satisfied the "must-consider" requirement. Most recently, the American Recovery and Reinvestment Act of 2009 ( P.L. 111-5 , ARRA) extended the production tax credit for qualifying renewable electricity technologies (since expired), and modified tax provisions for new plug-in vehicles (plug-in hybrids and pure electric vehicles) along with other actions and funding to advance the Smart Grid. Modernizing the grid is a focus of recent legislation in Congress. On September 9, 2015, the Senate Committee on Energy and Natural Resources reported S. 2012 , the Energy Policy and Modernization Act; on November 19, 2015, the House Committee on Energy and Commerce reported H.R. 8 , the North American Energy Security and Infrastructure Act of 2015. Provisions addressing customer-side technologies, grid-scale energy storage, increasing reliability, and integrating new technologies are included in the bills. The electricity industry is unlike most industries in that the product it produces is important to the functioning of our modern commercial society. Produced using economies of scale, electricity has been a fairly inexpensive enabler of national economic activity. But the convergence of many factors—new environmental regulations, an aging electric utility infrastructure, the growing availability of cost-competitive consumer-oriented electricity technologies, and state implementation of policies to advance renewable electricity—is presenting challenges to the electric utility industry while providing consumers with increasing choices for obtaining electric power. An evolution to some version of a new Utility 2.0 model capable of providing for customer choice in a clean energy future has been advocated by some as the next logical step for the electric utility industry. The electric utility industry would likely argue that before the United States can shift to Utility 2.0 , the obligations of today's Utility 1.0 model must be considered in plans to move forward. Such obligations would include the unrecovered costs of power plants and other infrastructure, and environmental and public safety obligations related to legacy coal and nuclear power. It may well be assumed that the current electric utility model will continue to evolve. A key to the future is likely to be cost control for many electric utilities, so that utility electricity prices will be competitive with other choices. Conversely, as utility customers seek to control their own costs or power-related decisions, the service choices offered to entice them to stay utility customers will probably increase, especially as the DG option becomes potentially more attractive. The options for electric utilities to satisfy these customers in the future may even include support services for customer self-generation beyond merely providing backup power. Congress began to address the move of the electricity utility industry away from the regulatory compact concept by introducing competitive providers to the electric utility industry with PURPA, and reinforced competition as federal policy with EPACT92. Several congressional bills have contained provisions to further a range of technologies and paradigms, especially in the various states-must-consider standards. In the future, Congress may yet consider if a formal legislative initiative would be required to move the electric power industry to a clean energy power system should that be the goal. Congress may also consider legislation if a market failure is perceived or if consumer choice is seen to be unduly constrained.

Summary: In the United States, the modern electric utility industry began to emerge about 100 years ago, guided by a philosophy which came to be called the "regulatory compact." Under the compact, state and local governments generally granted the right to provide electric power in a designated service territory, in exchange for an obligation to serve all electric power customers. Much of the nation's power generation and delivery infrastructure was built under this arrangement, with customers ultimately paying for the costs of electricity services. However, the electric utility model nowadays is under pressure as the industry deals with issues such as the aging of power generation assets, the implementation of new environmental regulations favoring cleaner, low carbon emission power generation choices, and the development of technologies providing options for customers to self-generate electric power. Some observers argue that new technologies are leading to a distributed generation (DG) future for customers, supported by utility base load generation and infrastructure. Various states and jurisdictions have begun initiatives to look at what a new "regulatory compact" could specifically encompass, with cleaner electric power and new services as the driving force behind utility investments. And the Environmental Protection Agency's regulations to reduce greenhouse gas emissions favors renewable electricity as the technology of choice for new power generation. While the electric utility industry seems to be fully aware of the potential for change, the question is how much the industry will embrace it. Some companies may see DG as appealing to only a small segment of the market, but in times of shrinking revenues, any market share loss can be significant. The Edison Electric Institute contemplates that the potential rise in DG, and requirements for net metering payments (without "appropriate" compensation by net metering customers for use of the grid), could be a threat to the regulatory paradigm that allows costs of providing service to be recovered from the consumers who benefit from grid services. Regulators will be challenged to recognize and plan for the possibilities of change, with its potential costs and implications for electricity industry structures. A key to the evolution of the current electric utility model is likely to be cost control for many utilities, so that prices will be competitive with other choices. Electric utilities may also have to offer enhanced service to consumers to entice them to stay utility customers, especially as it is becoming easier to go "off the grid." Utilities may even offer support services for customer self-generation beyond merely providing backup power. A convergence of electric power and natural gas utilities may possibly result in the future in a new, customer focused energy industry focused on providing consumer services. However, a formal transition requiring federal policy guidance for the electric utility industry may be required if, for example, the energy markets fail to transition smoothly to a clean power future, should that continue to be a policy goal. Market failures of this sort have been discussed in the past, with stranded assets and company bankruptcies posited as potential disruptions. Congress began to address the move of the electricity utility industry away from the regulatory compact concept by introducing competitive providers to the electric utility industry with the Public Utility Regulatory Policies Act of 1978, and reinforced competition as federal policy with the Energy Policy Act of 1992. Several laws enacted since then have contained provisions to further a range of technologies and paradigms in various "states-must-consider" standards. Congress may yet consider if a formal legislative initiative would be required to move the electric power industry to a clean energy power system should that be a goal. Congress may also consider legislation if a market failure is perceived or if consumer choice is seen to be unduly constrained.