Policy and Regulatory Approaches for a Modern Energy System
State legislatures and utility commissions play an important role in modernizing the grid. Their policies and the regulatory framework they create can promote or discourage investment in innovative technologies and energy management approaches. Legislatures have a number of options. They can create policies to encourage adopting and deploying new and emerging technologies, such as energy storage and demand response. They can work with public utility commissions to reshape the traditional regulatory framework in a way the better aligns customer and utility goals.
State legislatures have significant power to steer the course of policy through statutory and regulatory requirements. In most states, public utility commissions are limited by statute, with the legislature providing the foundation upon which commissions build their regulations. Those regulations, informed by the underlying statutes, play a significant role in directing investment and encouraging innovation in the energy sector. Public utility commissions can also direct studies to explore grid modernization and establish pilot programs.
Vertical Integration and Competitive Markets
While every state is a little different and hybrid systems do exist, there are two primary models for utility regulation in the U.S.—vertical integration and competitive markets. Whether a state falls into one category or the other determines some aspects of how its electric utilities pursue grid modernization efforts. However, even under these divergent regulatory models, most local distribution utilities are still under the jurisdiction of state utility regulatory commissions, which oversee how those utilities pursue grid modernization initiatives.
Vertically integrated utilities are natural monopolies. They own everything from generation to transmission and distribution networks and are responsible for delivering electricity to captive customers within a specific geographic region. While independent power producers and transmission companies do operate in a number of these markets, these utilities have traditionally owned, operated and maintained most of their own infrastructure. Customers are considered captive because they have no other options for electric service. State public utility commissions exert regulatory oversight, reviewing rates and capital projects, such as infrastructure investments. Municipal utilities and electric cooperatives are generally not subject to state PUCs and are governed by a board, operated as a city department or report to city councils.
In states that have chosen to rely on competitive markets, the investor-owned utilities have been restructured so that generation, transmission and distribution are functionally separated. In restructured states, merchant power plants sell power into wholesale markets run by grid operators—commonly referred to as independent system operators (ISOs) or regional transmission organizations (RTOs)—which, in turn, sell that power to local distribution utilities. Those distribution utilities deliver electricity to end-use customers and are still regulated by state PUCs, though customers may have the opportunity to purchase power through alternative retail service providers.
Grid modernization initiatives—such as smart meter deployment—are often submitted to PUCs through rate cases, which attempt to justify the need for infrastructure investments and their impact on consumer rates. PUCs review those proposals and approve or deny them. While a number of states require utilities to submit integrated resource plans (IRPs) for approval by state regulators, there is a growing movement to expand this concept to integrated distribution system planning. In most cases, IRPs deal with bulk power issues of forecasting future load and detailing how the utility plans to meet that load through demand-side or supply-side resources.
Integrated distribution system planning assesses physical and operational challenges in the local distribution system and prepares it for anticipated future changes in the use of distributed energy resources and other grid technologies. The goal is to establish a process and an integration protocol that will allow the system to adopt new technologies as seamlessly as possible. These efforts require utilities to look at the challenges facing specific sections of their systems caused by load growth, increased penetration of DERs and aging infrastructure. Like the IRP process, integrated distribution system planning is intended to be transparent to policymakers and the public.
To promote this process, DOE has supported a joint effort between the National Association of Regulatory Utility Commissioners (NARUC) and the National Association of State Energy Officials (NASEO) to create a forum for states to develop new approaches for utility system and resource planning. The NARUC-NASEO Comprehensive Electricity Planning Task Force, announced in February 2019, will give officials from 15 states and Puerto Rico the opportunity to learn more about the integrated distribution system planning process and how to incorporate it into state planning efforts.
As states move closer to innovative distribution system models, there can be effects on the wholesale transmission end of the system. Historically, grid operators control power flows moving in one direction—toward the end users in distribution networks. They take power from a limited pool of generators and send it through the grid to distribution networks, which deliver the power to customers.
The process of managing the grid and the work of grid operators could become substantially more complicated if power is coming from a much greater number of generators located at many different points on the grid, and potentially flowing from the distribution grid onto the transmission grid. On the technology side, the coordination and operational controls necessary to do this are currently being developed. However, work will also need to be done on the policy side, as unresolved questions over state and federal jurisdiction, compensation and power flow management will need to be addressed.
In some cases, RTO and ISO rules can limit the services and programs that distribution utilities are able to offer. One example is the confined access to markets that energy storage and demand response providers have faced in recent years. These programs cannot exist unless the market is constructed to value and allow them.
FERC has taken up both issues in the past decade to facilitate adopting new technologies. In 2011, FERC approved Order 745, which required wholesale markets to compensate demand response programs at the same rate received by generators. For example, if a demand response program lowered customer demand by 2 MW, it would be compensated as if it had generated 2 MW of electricity. To accommodate new storage technologies, FERC issued Order 841 in 2018, which required wholesale markets to develop rules that enable energy storage systems to participate more fully in electricity markets, allowing owners to be compensated for their full range of services. This concept is now under consideration before FERC in relation to DER aggregation, to determine whether distribution-level aggregated DER capacity can participate in transmission-level markets, raising some early questions over jurisdictional issues.
Public Power and Cooperative Utilities
Publicly owned utilities and electric cooperatives, while working to deliver the same services as investor-owned utilities (IOUs), have some distinct differences in their approach. IOUs must follow the regulatory structure laid out in statute and satisfy the requirements of the public utility commission in their states, while working to get a return on investments for shareholders. Municipal utilities are run by cities and must answer to the city council while electric cooperatives are nonprofit entities owned by their customer-members. Co-ops are governed by an elected board of directors.
Although cooperatives and municipal utilities do not have a profit motive and answer to city council or a board of directors instead of investors, they may still have a bias toward selling more electricity. This is because debt holders and debt raters may apply pressure to sell more in order to assure repayment. The Los Angeles Department of Water and Power, a municipal utility, adopted decoupling to promote energy efficiency and reduce the pressure to sell more electricity. This has allowed city managers and planners to change their focus from revenue recovery and increasing sales to goals such as lowering energy production and delivery costs through efficiency programs.
Since cooperatives often serve rural areas with lower population density, the remoteness of facilities and greater distance between structures can result in higher costs for adding services and technology. However, co-ops have found that modernizing infrastructure, by installing smart meters, for example, can have great benefits in low-population areas. Smart meters decrease costs by eliminating in-person meter-reading, while offering improved service, reduced outages and quicker recovery times.
State Policies for Grid Modernization
States are driving grid modernization through a variety of approaches, including establishing study commissions, developing broad grid modernization legislation, and providing grants for researching and developing smart grid technologies. In recent years, several states, such as California, Minnesota, Missouri, New Hampshire and Washington, have enacted legislation supporting broad grid modernization efforts.
States are also creating policies that encourage greater deployment of new and emerging technologies, including those that promote distributed energy generation, demand response, energy efficiency, smart grid technologies, distribution system planning and energy storage targets. Distributed energy resource deployment is also being driven by economic factors. As these technologies become increasingly competitive with traditional generation sources, such as coal and natural gas, DER adoption rates have steadily risen. The growth of DERs, resulting from policy efforts and increasing economic viability, is driving the need for a more complex energy grid. Ultimately, policymakers are responding to constituents, energy companies and industry innovators as they work to create a more reliable, efficient and flexible system that offers tailored customer solutions at an affordable price.
One step taken by several states is adopting the Next Generation Distribution System Platform (DSPx), which uses DOE grid architecture principles to develop holistic plans that can guide grid modernization efforts. The goal is to help plan and facilitate grid modernization decision processes so they better align the expectations of regulators, utilities and technology developers. These efforts have been initiated by state public utility commissions in a number of states, including California, Hawaii, Minnesota, New York and Ohio.
Renewable Portfolio Standards
Renewable portfolio standards (RPS) require utilities to ensure that a percentage, or a specified amount, of the electricity they sell comes from renewable or clean energy sources. Roughly half of the growth in U.S. renewable energy generation since 2000 can be attributed to state renewable energy requirements. These standards are helping drive the growth of distributed generation. Much of the growth is taking place on the distribution grid and pushing along other technologies, such as smart meters and energy storage that can help manage the increase in customer-generated power.
Renewable energy policies help drive the nation’s $64 billion market for wind, solar and other renewable energy sources. These policies can play an integral role in state efforts to diversify their energy mix, promote economic development and reduce emissions. Twenty-nine states, Washington, D.C., and three territories have adopted an RPS, while eight states and one territory have set renewable energy goals. State RPS policies have established a variety of percentage requirements for renewable energy and clean energy, though many states with RPS policies require between 10% and 45% renewable energy. During the 2018 and 2019 legislative sessions, a significant number of states enacted legislation to increase their RPS policies, with many states establishing ambitious renewable and clean energy targets. At least six states—California, Hawaii, Maine, New Mexico, New York and Washington—Washington, D.C., and Puerto Rico have enacted legislation establishing time-based requirements for 100% clean or carbon-free energy.
Many states have established provisions, including carve-outs and credit multipliers, in their RPS policies to encourage greater deployment of distributed generation, such as rooftop solar. Carve-outs require a certain percentage of the overall renewable energy requirement to be met with a specific technology, while credit multipliers award additional renewable energy credits for electricity produced by certain technologies. At least 21 states and Washington, D.C., include distributed generation in their targets. For example, Colorado has a 3% carve-out for distributed generation, while Illinois has a 1% annual requirement for distributed generation. Delaware has a 3.5% solar PV requirement by 2025 and Missouri has a 2% carve-out for solar. Nevada, Oregon and Washington have established solar and distributed generation credit multipliers under their RPS policies. Nevada has a credit multiplier for photovoltaics and on-peak energy savings. Oregon has a credit multiplier for solar PV installed before 2016, while Washington has a credit multiplier for distributed generation.
Although RPS policies have historically been significant drivers of growth in renewable energy generation and capacity, their role has diminished with the rapid decline in solar and wind costs. According to the Lawrence Berkeley National Laboratory, RPS policies were responsible for just 34% of all U.S. renewable capacity additions in 2017. Renewable energy has become increasingly competitive with conventional energy generation costs, which is driving greater deployment.
Recent Notable Renewable Portfolio Standard Increases
|State, Bill No.
|California SB 100 (2018)
||100% clean energy by 2045, 60% renewable by 2030
|Hawaii HB 623 (2015)
||100% renewable energy by 2045
|Maine Senate Paper 457 (2019)
||100% renewable by 2050, 80% by 2030
|Nevada SB 358 (2019)
||50% renewable by 2030, non-binding 100% carbon free by 2050
|New Mexico SB 489 (2019)
||100% carbon-free by 2045
|New York SB 6599 (2019)
||100% carbon-free electricity requirement by 2040
|Washington SB 5116 (2019)
||100% carbon-free by 2045
|Washington, D.C., Bill 904 (2018)
||100% carbon-free by 2045
|Puerto Rico SB 1121 (2019)
||100% carbon free by 2050
Energy Efficiency Resource Standards
One policy that states have implemented to encourage greater energy efficiency and deployment of efficient technologies is energy efficiency resource standards (EERS). EERS requires utilities to achieve a specified amount of energy savings through energy efficiency programs within a specified timeframe. State EERS can apply to electric or natural gas utilities, or both, depending on the state. Like RPS policies, EERS establishes long-term goals, which send a clear signal to market actors about the importance of energy efficiency in utility program planning and creates a level of certainty that encourages large-scale investment in cost-effective efficiency.
EERS plays an important role in driving sustained investment in energy efficiency and is one of the most effective state policies to guarantee long-term energy savings. According to the American Council for an Energy-Efficient Economy, states with an EERS policy in place have shown average energy efficiency spending and savings levels more than three times higher than those in states without an EERS policy. States see these policies as necessary to overcome the bias created by the regulatory framework, which induce utilities to prefer power plant and infrastructure projects over efficiency measures that result in less electricity sales. These policies are helping drive the implementation of new grid technologies—connected heating and cooling systems, appliances and other devices—which are providing many more opportunities for energy savings.
At least 27 states have established an EERS either through legislation or the state public utilities commission.
EERS policies require a minimum amount of savings and allow utilities to choose how to achieve the required savings—such as rebate programs for energy efficient appliances and smart thermostats, home weatherization and lighting replacement programs, behavior-based programs, supply-side efficiency improvements, and combined heat and power or waste heat recovery applications.
In addition to providing utility flexibility, an EERS can have several other potential benefits. These policies provide defined targets that utilities can incorporate into their strategic planning and that regulators can use to evaluate and reward performance. Unlike minimum spending mandates for energy efficiency programs that have been implemented in several states, EERS encourage utilities to make cost-effective investments in energy efficiency. Finally, the minimum level of savings required by an EERS policy can also contribute to states’ achievements of environmental, health and economic development goals.
There are, however, challenges and costs associated with the implementation and operation of an EERS. Administering an EERS requires organization and communication between public utility commissions, utilities, efficiency program administrators and program evaluators. The traditional regulatory model, which compensates utilities based on capital investments and electricity sales, both of which may be reduced by energy efficiency policies, can also be a barrier. Decoupling, discussed in the Utility Business Models section, addresses this barrier and can be a useful energy efficiency companion policy. Additionally, measuring and verifying the energy savings resulting from efficiency programs can pose a challenge.
In addition to EERS, states can increase investment in energy efficiency by requiring utilities to include energy efficiency resources in their IRPs or by requiring utilities to spend a specified percentage or amount of their annual revenue on energy efficiency programs.
Electricity providers and grid operators consider demand response programs to be increasingly valuable resource options whose capabilities and potential impacts are greatly expanded by modern grid technologies. Demand response is the ability to adjust customers’ heating, cooling or other energy services in exchange for monetary credits on their bill. It is helpful for reducing stress on the grid during peak consumption times or power outages, integrating renewable energy resources and providing other grid services. It provides customers with the ability to shape their electricity consumption throughout the day, resulting in lower electric bills.
As states continue their efforts to modernize the electrical grid and deploy larger amounts of renewable energy, they are increasingly exploring policies to encourage deployment of demand response resources to better manage electricity demand and integrate intermittent energy resources. California enacted SB 1414 in 2014, which accelerates adopting demand response by requiring utilities and regulators to include it in IRPs. The bill also requires regulators to ensure appropriate valuation of demand response resources. In 2017, California enacted SB 801 that, among other provisions, requires the Los Angeles Department of Water and Power to maximize the use of demand response, renewable energy and energy efficiency in the area affected by the Aliso Canyon natural gas leak in 2016.
Washington enacted HB 1826 in 2013 to promote technologies and practices that lower integration costs. The law requires integrated resource plans, which utilities submit regularly to state regulators. They outline how utilities plan to meet forecasted annual peak demand and identify methods and commercially available technologies, including energy storage and demand response, for integrating renewable and distributed resources. In 2018, the Washington Utilities and Transportation Commission approved a request for proposals filed by Puget Sound Energy to procure demand response programs for 2019 through 2023 to meet a 351 MW capacity need the utility will have by 2023.
Vermont enacted HB 40 in 2015, raising its renewable standard to 75% by 2032. As part of this mandate, 12% of the standard can be met with energy transformation projects, which could include energy efficiency, energy storage or demand response.
In 2018, Massachusetts enacted HB 4857 establishing the first clean peak standard in the country. The bill directs the state’s Department of Energy Resources (DOER) to establish a clean peak standard that would require utilities to provide a minimum percentage of KwH sales to customers in the state from clean peak resources, including certain renewable resources, energy storage systems and demand response resources. DOER must determine the percentage of sales during seasonal peak load hours that electric utilities must meet beginning in 2019. DOER will determine the initial standard and each year thereafter the standard will increase by 0.25% of sales. The department will also establish a minimum percentage of the clean peak standard that must come from demand response resources.
Montana and South Carolina enacted legislation in 2019 to require utilities to include demand response and demand-side management programs in their IRPs. Montana HB 597 requires utilities to submit long-range IRPs every three years and for these plans to include demand-side management programs. The bill also allows the state’s Public Service Commission to authorize utilities to recover the cost of demand-side management programs in their rates. Similarly, South Carolina HB 3659 requires utilities to submit IRPs, which must include an evaluation of potential demand response resources, in addition to other technologies.
Energy Storage Targets and Mandates
Energy storage technologies, including batteries, pumped hydro, super capacitators and flywheels, store excess electricity generation and can quickly dispatch power to the grid as needed. These technologies offer a variety of benefits, including decreasing the need for costly grid upgrades, improving the electric grid’s stability and reliability, and enhancing power quality and reliability. Energy storage also facilitates greater use of renewable energy resources by smoothing out variable generation from renewable technologies, such as wind and solar. When paired with microgrids, energy storage can ensure power reliability and enhance grid resiliency.
States have shown increasing interest in energy storage technologies as the cost of lithium-ion batteries has declined, establishing a number of energy storage mandates to encourage deployment of this emerging technology. In 2017, at least 31 states took legislative and regulatory action related to energy storage. These actions included conducting studies, amending resource planning and interconnection rules, considering incentives for storage systems, adopting procurement targets and deploying storage facilities.
Several states have enacted energy storage targets, including California, Massachusetts and Oregon, while Connecticut, Nevada, New Jersey and New York have directed state regulators to establish targets.
In 2013, the California Public Utilities Commission established an energy storage target of 1.3 GW by 2020, making California the first state to adopt an energy storage mandate. In 2017, Massachusetts enacted HB 4857, increasing its previous energy storage target to 1 GWh by 2025. New York enacted legislation in 2017 to create a statewide energy storage target. Shortly after signing the bill, Governor Andrew Cuomo established a target of 1.5 GW of energy storage by 2025 through a series of clean energy proposals. In late 2018, the New York Public Service Commission increased the state’s commitment, raising the energy storage target to 3 GW by 2030. In 2018, New Jersey became the fifth state to adopt an energy storage target by enacting AB 3723, which directed the Board of Public Utilities to study and establish a process for reaching 600 MW of energy storage by 2021 and 2 GW by 2030. Nevada enacted energy storage-related legislation in 2017 that requires the PUC to investigate and establish energy storage targets.
Other states have advanced a variety of different policies, including energy storage tax credits in Hawaii, Maryland and New York. In addition, states have commissioned studies and sought state agency recommendations, provided funding for storage pilot projects and required storage to be considered in the utility planning process.
Net metering has been instrumental to the growth of distributed resources in many states since it allows distributed generation customers to sell excess electricity to the utility and receive a retail rate credit on their utility bill. The credit offsets the customer’s electricity consumption during other times of the day, reducing the amount of electricity the customer needs to purchase. Minnesota was the first state to adopt net metering compensation at the retail rate in 1983 and at the policy’s height, 44 states, Washington, D.C., and several territories had net metering policies. Some states compensate net exports at less than the full retail rate, a practice referred to as net billing. Some call this approach net metering as well.
Forty states, Washington, D.C., and five territories provide net metering as of July 2019. Utilities in two additional states—Idaho and Texas—have voluntarily adopted net metering programs. At least five states—Arizona, Georgia, Hawaii, Mississippi and Utah—have statewide distributed generation compensation rules other than net metering. As of July 2019, at least six additional states—Connecticut, Illinois, Indiana, Kentucky, Michigan and New York—have passed legislation or issued public utility commission decisions to phase out retail rate net metering after a certain date. Maine enacted legislation (House Paper 77) in May 2019 ending gross net metering and reinstating retail-rate net metering. The 2019 bill largely reversed a 2017 public utilities commission decision to replace net metering with a buy-all, sell-all compensation program.
Although net metering policies have helped expand access to distributed renewable energy, they have also generated questions of equity and cost-shifting.
Originally designed to spur a nascent technology, net metering’s success has led to debates on the policy’s sustainability in virtually every state legislature or utility commission. While a net metering customer provides generation and other benefits to the grid, some feel the customer is not adequately paying for the operation and maintenance of the electricity transmission and distribution system. If customers are paid retail rate, some contend, they may be shifting grid operation costs to their neighbors. Others claim that the reliability, demand reduction and peak savings benefits may make distributed solar valuable enough to receive retail rate.
As penetration of distributed energy resources increases, numerous state legislatures and public utility commissions are discussing the best way to balance customer demand for distributed generation with the effects new technologies have on the electric grid. This includes exploring ways to appropriately assess the actual costs and benefits to the energy grid and all customers.
States such as Arizona, California, Hawaii and New York have explored next-generation compensation approaches that attempt to comprehensively value DER, not only solar energy. In 2013, California passed AB 327, requiring the California Public Utilities Commission (CPUC) to create a successor tariff for net metering, termed NEM 2.0. The CPUC decided in January 2016 to preserve the retail rate credit through 2019 and guarantee net metering credits for existing customers for 20 years after they are connected. The decision also requires all new net metering customers to be subject to provisions under a new successor tariff, which includes interconnection fees, non-bypassable charges for all electricity consumed from the grid and participation in time-of-use rates.
In 2015, the Hawaii Public Utilities Commission issued a ruling that ended conventional net metering. The PUC designed two interim tariff options to replace net metering—a grid-supply option and a self-supply option. The interim tariffs were replaced in 2017 by two new tariffs—a customer grid supply plus option and a smart export option.
As part of its Reforming the Energy Vision proceeding, New York has addressed the transition from traditional net metering to a new tariff to appropriately value and compensate DERs. The New York Public Service Commission (PSC) established the Value of Distributed Energy Resource (VDER) tariff, or the Value Stack, to replace net metering. The VDER is designed to compensate DER projects based on when and where they provide electricity to the grid. In March 2017, the PSC approved an order adopting Phase 1 rates for the VDER tariff. The Value Stack order was expanded in September 2018, and recently updated in April 2019.
In September 2018, the Arizona Corporation Commission approved a replacement for net metering called the Resource Comparison Proxy. The slightly lower rate applies to new distributed solar owners and, combined with new higher monthly meter fees, is designed to address potential cost-shifting issues associated with net-metering. The commission also approved a special rate for new solar customers with home storage systems.
Non-wires alternatives (NWAs) leverage microgrids, distributed solar, energy storage, energy efficiency, demand response and other energy solutions to delay or avoid construction of costly transmission, power plants or other infrastructure. Traditionally, when infrastructure needed to be replaced or upgraded to meet growing demand, utilities procured and installed the equipment and were able to earn a rate of return on those capital expenditures via the regulatory framework. The host of new technologies integral to the modern grid offer more creative ways to address infrastructure needs while improving benefits for customers and the environment. Since this approach is relatively new and may involve harmonizing the use of many newer energy technologies, utility planning procedures do not systematically emphasize consideration of these solutions.
Several states are now requiring that utilities consider non-wires solutions in their plans to meet energy needs. In New York, which also requires utilities to consider non-wires solutions, Con Edison implemented one of the largest NWAs to date with the Brooklyn-Queens Demand Management program, which deferred a $1 billion substation upgrade with a $200 million investment in demand response and other measures. Bonneville Power also found substantial savings through non-wires alternatives. The utility canceled a $1 billion transmission line and is instead using demand response to manage line congestion, rather than overbuilding for a few peak hours of demand each year. Rhode Island passed a law in 2006 requiring utilities to consider cost-effective energy efficiency and other demand-side measure before building costly supply-side solutions. Maine, Vermont and California also have been working to encourage or require consideration of non-wires alternatives.