TODAY’S STUDY: How To Value And Grow Distributed Energy Resources
NARUC Manual on Distributed Energy Resources Rate Design and Compensation
Staff Subcommittee on Rate Design, November 2016 (National Association of Regulatory Utility Commissioners)
In November 2015, NARUC President Travis Kavulla announced that the newly created Staff Subcommittee on Rate Design would create a manual to assist commissions in considering appropriate rate design and compensation policies for distributed energy resources (DER). The reason for this manual is that the nature of electricity delivery, consumption, generation, and grid itself are changing, and changing rapidly. Instead of traditional, one-way delivery of electricity from large, central station power plants located far from load, via high voltage transmission lines, to lower voltage distribution lines, and, finally, to the home, technologies are now available directly to customers that allow them to generate their own electricity, respond to prices, reduce (or increase) demand when useful to the system, or store electricity for use at a later time. Many of these technologies are affordable to the majority of customers, with more technologies coming down in costs over the near term. Understanding how DER impacts the grid itself, including reliability, is an important factor, but also understanding where, when, and how DER can benefit the grid is of equal value. This manual attempts to provide regulators and stakeholders with information on how to address these opportunities, while maintaining affordable, reliable, safe, and secure electricity.
This Manual is organized to provide regulators with a comprehensive understanding of the question of how does DER affect regulation. It lays out a background on the principles of rate design and compensation, the availability and use of new technologies, an explanation of what is DER, and describes a set of certain types of DER. This is to provide a regulator ample background of not only how DER impacts existing regulatory and utility models, but also provides a foundation for considering how to evolve along with this transition. The Manual then describes a variety of rate design and compensation options that a jurisdiction may consider—the options described herein are not the only ones available to a jurisdiction, but are the most prevalent under discussion today. The Manual goes through them laying out the pros and cons of the option, and providing regulators with information to assist them in their consideration. Lastly, the Manual outlines a few practical ways for it to be used, including examples of determining costs and benefits of DER, questions for a regulator to support an investigation into appropriate rate design and compensation for DER, and how to use some of the details in this Manual to support a decision-making process.
This version of the Manual is not the final word. As noted throughout, customer preferences and adoption rates, and the implementation of new technology on the grid side will continue to grow, and with that growth comes new evidence, more solutions, and, perhaps more questions. The lack of more widespread experience with certain types of DER, and the shortage of available data at this point in time means that we have barely scratched the surface of what this future could look like. Commissions around the country are opening proceedings on the topics raised in this Manual almost every month; those proceedings will take time, the results of those proceedings will then take time to implement. This Manual provides a benchmark for those discussions and solutions and is limited only to the discussion rate design and compensation for DER; as noted throughout, there are a number of other topics that are closely related to this topic that are better suited for its own document. This Manual will be revised at some point in the future, when conditions or demand warrants it. Supplements may be added in the intervening years to assist with definitions or processes, but experience and data will drive its next iteration.
This Manual was created with the assistance of staff from around the country, many of whom are in the midst of the very same topics addressed here. The Manual is not designed to answer questions, but to provide regulators with support. Even at low levels of adoption, a jurisdiction should not be content to wait until adoption levels start to increase; planning for the future will enable a jurisdiction to have the tools in place when it is ready to act. Being proactive and maintaining awareness of customer adoption and behaviors will greatly alleviate the strain on a commission, utility, and stakeholders when it does come time to act. By acting now, even if the conclusion is to keep a particular policy in place, does much to inform a commission, and better understand what it may need to do in the future, and can put the commission on a path towards a smooth transition to this future…
Mechanisms and Methodologies…Rate Design Options…Demand Charges…Fixed Charges and Minimum Bills…Standby and Backup Charges…Interconnection Fees/Metering Charges…DER Compensation Options…Net Energy Metering…Valuation Methodology…
A Path Forward for Regulators
The majority of content in this Manual reflects the traditional role of the regulator: determine utility costs, authorize recovery of prudent costs, determine which customers will pay for which costs, and set rates for an opportunity to recover those costs. The impetus for this Manual is the changes occurring in the industry. Some of the changes, like improved communications and sensor technology, continue to enhance visibility into the grid and have added cost-effective choices for serving customers. What is completely new is that the customer is no longer simply a passive taker of electricity. This fundamental change allows a customer to produce its own electricity, invest in technology to take more control over its own usage, send electricity or provide other services to the grid, and have more flexibility and responsiveness to changing prices and supply of electricity. This section provides an overview of information and questions a regulator may need to address to effectively use this Manual to best meet the needs of the particular jurisdiction. The section starts by outlining some high-level questions, data needs, and distribution system planning before outlining some indicative rate design, compensation, and cost–benefit questions.
Questions to Support a Regulator
Below is an initial, indicative set of questions that a regulator may ask to gauge the status fof DER adoption in the state, the level of preparedness at the utility to integrate or utilize DER, how the existing rate design affects DER generally and certain DER specifically, and considerations for next steps. This is by no means an exhaustive list. Assessing the current situation: • What is the current adoption level of DER in the jurisdiction? o What is the number of interconnection agreements? o What is the number of EVs on EV-specific rate designs? o What is the number of customers on a DR program or the amount of available DR from the utility or aggregators, or both?
• Where is the DER located? • Does the regulated utility have sufficient visibility into its distribution grid to monitor impacts of certain types of DER on its system? • What issues, if any, have already come to the utility’s or regulators’ attention concerning the effect of DER on the grid and regulation? • When was the last class cost-of-service study performed? Does the regulator have sufficient information about rate and cost impacts from DER on customer classes? • How are the different types of DER currently treated in rate design, compensation, planning, and so forth? • On a prospective basis, how does any policy or regulation address DER investments that lead to DER benefits, if any? Exploring DER rate design and compensation: • What role is expected of DER in the short and long term? What is the regulator’s vision regarding how these changes affect the industry? • How does that role affect utility planning, revenue recovery, and investment decisions? • What does different DER provide in the context of the utility’s duty to provide generation, transmission, and distribution while satisfying environmental and other public policy requirements? • How should a jurisdiction analyze costs and benefits of any particular DER technology or service? • How does the jurisdiction minimize harm and optimize benefits? • How does a jurisdiction address these questions—does a jurisdiction open one generic proceeding, or does a jurisdiction address them piece by piece? • How does a regulator address the asymmetry of information inherent in utility regulation when discussing the grid? • How do the different scenarios of DER adoption rates affect utility and regulatory processes? • Does the utility have access to the data necessary to inform itself and the regulator about its system, costs, and hosting capacity? How can these data be shared with other stakeholders in a way that is both useful but also appropriately protects the data? • How should the jurisdiction ensure that all stakeholders participate in any proceeding? Traditional participants in regulatory proceedings may no longer capture the full views of stakeholders. • When, and at what pace, should the jurisdiction act? • Are the regulators moving away from traditional utility regulation and rate making—for instance adopting a so-called performance-based distribution system as a platform (e.g., New York REV), or a Transactive Energy regulation? If so, how does DER fit into, or drive, that vision? In reviewing any particular proposal, a jurisdiction may consider the following: • Does the proposed DER compensation mechanism accurately and objectively assess the costs, benefits, and risks of DER? • To what extent does the proposed rate structure account for core infrastructure costs and impacts relating to the grid? • Do the projected benefits of the DER outweigh the likely costs to the utility, to other customers, and to society at large? Benefits might include bill impacts and compliance with environmental mandates; costs might include cost shifts, impacts on utility planning, and possible reliability implications. • Does the proposal result in a cost shift? • Are possible cost shifts minor, reasonable, and non-regressive? To what extent any cost-shift is acceptable. • If costs arise as a result of DER deployment, will the rate structure ensure that the causer of the cost pays? • Does the proposal ensure equitable access to benefits, such as decreases in electric bills? • Are there alternatives to realizing the core public policy objectives at issue in the proposed DER compensation mechanism? Are there alternative paths to the public good at issue? • Should a regulator consider a separate class for DER customers? • Does the proposal further core notions of regulatory neutrality and parity? Does the proposal endorse a particular technology or business model, or does it create opportunities for an array of market participants? • To what extent are regulators formally expanding their distribution system planning process in their jurisdiction? Does the regulator already have, or is there an adequate level of, visibility into the utility’s planning process and operations?
DER, by definition, primarily affects the distribution system since that is where it is located. That is not to say DER cannot impose costs on, or provide benefits to, the broader generation and transmission systems. However, for the most part, the costs and benefits manifest themselves at the local level, and as such that is where DER is forcing regulators and utilities to focus.
These trends seem to generally require regulators to have more visibility into and oversight of the planning of a utility’s circuits and broader distribution system. They often require the utilities themselves to have far greater visibility into their own systems. Fortunately, the smart grid technology driving these improvements should represent opportunities for more efficiencies to benefit utilities and customers alike. What data are needed by regulators?
Below is a partial list for thinking about types of data or other information for this analysis: • Does the regulator have access to the number of DER, different types of DER, and locations; number of customers who have adopted DER, the costs and benefits associated with those DER; a recent cost of service study; or, an indication or study showing any cost-shifting, by class, geography, or socio-economic? • What is the hosting capacity on various parts of the distribution system? Also, what are the unique, localized circumstances that drive opportunities or barriers to increased benefits from DER adoption? • How are transmission, generation, and distribution costs and benefits identified, determined, and accounted? o What is the proper level of granularity in data to examine and ensure efficient accounting of DER? o What is the best way to examine and set which costs and benefits should be socialized and which should be borne by the individual customer? • How can the regulators help society efficiently allocate investment resources, especially between regulated utilities and independent consumers? How can the regulators encourage efficient acquisition of DER? • What additional data or analyses are needed for the proper visibility and planning for the grid and DER? Below are examples of potential types of data a regulator may want to obtain, ensure that a utility is collecting, or make available to stakeholders to assist in analyzing grid needs, planned investments, or general grid design and optimization.
Role of Technology
Advanced technologies can not only support the operations of a grid, but also support regulators in making decisions about rate design. Communication abilities are being coupled with advanced technologies, providing the utility, and potentially the regulator as well, with data that can be used to make informed decisions about DER compensation. The resulting data can help the utility measure the impacts of DER, more accurately measure consumption and generation, and analyze the need for DER at a specified level (e.g., meter, bus, feeder, circuit). With this information the regulator can also make more accurate cost and benefit analyses of DER; can evaluate the current rate design methodology; and can continuously reevaluate the proper methodology as levels of adoption change, new technologies and services are developed, and other objectives or public policy goals need to be met. Additionally, using this information, a regulator can better identify adoption levels across a jurisdiction. By being aware of the continual pace of change and adoption rates of technologies by customers, a regulator can identify appropriate strategies for addressing these changes in a more proactive manner. As discussed elsewhere, certain advanced technology investments are required to implement the several methodologies described above. For example, without an advanced meter, implementing an option like TE will not be feasible. These technologies allow for more granular information about usage and production to be collected; this information can then be used as a foundation for consideration of appropriate methodologies. However, decisions on investments in technology should not be limited only to implementing particular methodologies; rather, decisions on utility investments should continue to rely on total benefits. In other words, specific investments should provide greater benefits than simply enablement of a specific methodology. Many technologies provide multiple benefit streams and enable greater opportunities. Understanding how these technologies fit in the larger context is important before approving any investment. Nevertheless, it will be important for regulators to maintain an awareness of the pace of technological change over time, as new technologies will provide new opportunities for identification of benefits and costs. These data can then be used to identify potential changes needed for existing rate design choices. Additionally, these data can be collected in real time. For example, traditional analog meters are read once a month, but digital meters connected to a communications network collect information on an hourly or 15-minute basis. Furthermore, meters connected to a customer’s Home Area Network (HAN) can be read in real time in increments as frequent as eight seconds. Having rate design options that can make use of this type of data may enable a wide variety of benefits available to the customer. This is but one example; technology is increasingly embedded in consumer products and can be leveraged for a potential wide variety of rate designs and compensation options. Technology implanted on the distribution grid can also provide important data for the development and implementation of DER compensation methodologies. Smart transformers, line monitoring, SCADA, hosting capacity, and other suites of services like ADMS and DERMS, allow for better integration of DER. By collecting information about the capability of the distribution grid in real time, utilities can have a clearer view of the state of the distribution grid. Knowing power flows, voltage fluctuations, and available capacity for feeders across the distribution system can greatly assist in finding DER in locations most beneficial to the grid. Having this information can also assist in developing appropriate DER compensation methodologies, as without this level of knowledge about the grid, DERs will be located with little input from the utilities. Similarly, recognizing how to use this information to understand adoption levels of technology will assist the regulator in determining when a change is needed.
Process for Working through the Questions
Ultimately, in determining appropriate rate design or compensation, a regulator will need to balance the various principles and goals of rate design and regulation. As a part of that process, a jurisdiction will have to weigh its unique legacy policies and technology and current situation in considerations related to impacts on utilities, DER customers, and non-DER customers, and other policy considerations of potential changes to rate design or compensation methodologies. This Manual provides two high-level examples below that may assist a jurisdiction in balancing these considerations. As more jurisdictions gain greater experience in working through these issues, and more data become available, this section may evolve in response to this experience. What follows is a framework that jurisdictions can use to guide them through this process.
1. Rate Design and Compensation
A regulator may consider the following questions regarding rate design and compensation: • Once jurisdictions have identified the nature of costs and benefits, how should this information affect rate structures and compensation mechanisms and inform the regulatory compact? • To what extent should fixed costs be collected through fixed charges? To what extent can alternatives fulfill the same purpose for the public good? • What amount of revenue responsibility shifting is acceptable, given that there are always intra- and inter-class subsidies? • To what extent should demand-related costs be collected through demand charges? While collecting these costs through demand charges may result in decreased intra-class subsidies, is the potential for confusion or the difficulty in responding to such price signals a consideration that outweighs the subsidy reduction and potential efficiency gain? To what extent can alternatives fulfill the same purpose for the public good? • To what extent should costs imposed on the system or previously paid by DER customers be directly attributed to DER customers as opposed to being borne by all customers? Relatedly, to what extent should benefits to the utilities system due to DER installation accrue to DER customers and to what extent should other customers share in these benefits? How and to what extent could a jurisdiction help facilitate investment in DER that benefits all customers? • To what extent should a jurisdiction take into account external benefits? While economic theory states that prices should reflect all externalities to result in the most efficient outcomes, federal and state incentives may already be taking some of these externalities into account (though perhaps in a less efficient way). A jurisdiction may prefer to rely on society at large to price these externalities, rather than levying that price on ratepayers of a utility.
2. Costs and Benefits
Decisions on an appropriate rate structure and how compensation policies affect, both for DER and non-DER customers, rely to a great extent on a jurisdiction’s opinions on the nature of costs and benefits. EPRI’s Cost Benefit Framework as related to DER offers a quick overview of one way to consider this question.208 The yellow column represents the types of impacts as a source of outputs from the distribution and bulk power system. The gray column identifies measurable impacts from each type, which includes costs and physical impacts to be monetized. The orange column represents those benefits that are to be monetized, which includes customer and societal impacts (bottom two boxes in fourth column). All are then combined to total the net societal benefits. According to EPRI, this “framework supports a variety of perspectives on DER accommodation. . . . the benefit-cost analysis distinguishes between net costs incurred by the utility (the utility cost function) and are therefore collected in rates, and benefits that accrue to customers and society and affect resource utilization—but are not priced by the market or administratively and are therefore not included in utility revenue requirements.”209 A jurisdiction must carefully consider the evidence on the nature of costs and benefits, and decide several key issues. Another way to analyze these issues is through the California SPM. The following graph is a summary of each cost-effectiveness test.210 The full SPM provides a breakdown of each test, including the pros and cons of each method. The commonly utilized “Societal Cost” test is treated as an offshoot of the “Total Resource Cost” test; in other words, while using the Total Resource Cost test, the regulator can add a value for costs or benefits to society, such as a social cost of carbon. The SPM is used across the country for cost-effectiveness testing for a variety of demand-side resources, primarily energy efficiency. In thinking about determining costs and benefits, a regulator may consider the following:
• To what extent does the grid provide benefits that are not captured by traditional measures of use? If a jurisdiction believes that the grid provides many benefits not captured by usage, whether volumetric or demand-related, that jurisdiction may lean toward changing rate structures to better reflect those benefits. • To what extent does DER lower utility costs? If DER provides significant cost reductions or avoids significant costs for the utility, that evidence should affect decisions on appropriate rate structures and compensation. • To what extent does DER benefit society at large? Identification and the attempted quantification of these benefits should also inform rate design and compensation structures. • To what extent do rates currently, and to what extent will they in the future, reflect the nature of costs and benefits?
Once these issues have been decided, the most appropriate potential options for rate design and compensation should be clearer. The choice, then, is which of the potential options that achieve some or all of a jurisdiction’s goals can or should be used. Certain options, such as time-varying rates and demand charges, require AMI or interval metering to utilize. Without such enabling technologies, a regulator may select another rate design or compensation option that achieves many of the same goals as its preferred option without the technological requirements. Effects of the choice on customers, both DER and non-DER, must also be taken into account when weighing options that achieve a regulator’s goals. Equity considerations between income levels, existing and future customers, classes, and technologies should also be taken into account. The delicate balance of all considerations such that the public interest is maximized is at the discretion of regulators in each jurisdiction, and multiple reasonable outcomes are possible.
Whether to Act Based on Adoption Levels
While it is important to take the time to accurately assess the appropriate structure of rates for DER (as well as other) customers, regulators should not tarry too long in establishing what they feel is an appropriate rate structure and compensation mechanism for DER customers. A very important factor in customers’ decisions on DER installation is the price signals sent by the rate design. If those price signals do not appropriately reflect a jurisdiction’s policies on cost-causation, the result will likely be an economically or socially inefficient amount of DER. Waiting too long to set up an appropriate pricing structure can also make grandfathering and equity considerations between future and existing DER customers more of an issue than they otherwise would be. Setting up an appropriate pricing and compensation structure should be done as soon as feasible, but there should not be so much urgency that the decision is made without all of the appropriate information. The results from such uninformed actions could be worse than no action at all. Adoption levels may, however, affect the amount and types of costs and benefits that accrue from DER installations. It is important to decide if different rate structures and compensation methodologies are appropriate for different stages of adoption, or if a single structure should be put in place that can deal with the differential impacts of various penetration levels. To the extent that it is decided that different rate structures are appropriate at different adoption levels, it should be made clear to customers whether grandfathering will apply so that the decisions on DER installation can take into account the potential for future rate changes.