TODAY’S STUDY: How To Price Distributed Energy
Distribution System Pricing With Distributed Energy Resources Jim Lazar and Ryan Hledik, Lisa Schwartz, May 2016 (Lawrence Berkeley National Laboratory)
Technological changes in the electric utility industry bring tremendous opportunities and significant challenges. Customers are installing clean sources of on-site generation such as rooftop solar photovoltaic (PV) systems. At the same time, smart appliances and control systems that can communicate with the grid are entering the retail market. Among the opportunities these changes create are a cleaner and more diverse power system, the ability to improve system reliability and system resilience, and the potential for lower total costs. Challenges include integrating these new resources in a way that maintains system reliability, provides an equitable sharing of system costs, and avoids unbalanced impacts on different groups of customers, including those who install distributed energy resources (DERs) and low-income households who may be the least able to afford the transition.
This report examines pricing issues related to the business relationship between electric distribution utilities and the owners of DERs. At a minimum, utilities will likely continue to supply most owners of DERs with backup and supplemental service and with various other grid services. Utilities will receive power from certain types of DERs and may be able to secure important grid reliability services from DERs as well.
The authors of this report have attempted to portray these issues from a perspective in the future, when these resources are assumed to be widespread, when there are “fleets” of thousands and millions of units that are already integrated into the distribution system. The report uses specific resources as examples, intended to illustrate the issues that utilities, regulators and consumers will face, not to exclude potential other resources that may have different impacts. Examples include:
• Grid-integrated water heaters
• Ice storage air conditioners
• PV systems with smart inverters
• Backup generators
• Battery and inverter-based storage systems
The pricing for services from the utility to customers with DERs, and for services DERs provide to the utility, can take many forms. This report examines four approaches to pricing these services:
1. Granular Rates: The pricing for services to and from customers with DERs is highly granular, with each service provided by each party separately priced.
2. Buy/Sell: The pricing for services to customers with DERs is in the form of a bundled traditional utility price. The pricing for services DERs provide to the utility is in the form of a resource-specific price reflecting the characteristics of the service.
3. Procurement Model: The pricing of services the utility provides customers with DERs is in the form of a bundled utility price. The services DERs provide to the utility are procured on a competitive basis, with third-party aggregators likely playing a role in presenting a value proposition to both the utility and the DER owner/host that meets their financial and other criteria.
4. DER-Specific Rates: The utility applies separate rates to customers with DERs, both for supplying backup and supplemental service and for procurement of services from DERs. Each type of DER faces a different type of rate, based on the characteristics of the resource and technology.
Each of these options is examined based on multiple evaluation criteria. These criteria are inevitably somewhat subjective and will vary geographically and temporally and evolve with technology. Criteria include:
• Economic Efficiency: Does the DER provide a net economic benefit that should be able to be shared in a way that makes all parties better off?
• Equity/Fairness: Does the pricing scheme ensure that DER owners/hosts are fairly compensated and that other customers do not bear costs in excess of what they would face without these DERs?
• Customer Satisfaction: Do customers enjoy better electric service, lower costs, or the perception of a better overall package of values?
• Utility Revenue Stability: Does the utility receive a fair and predictable level of revenues that track the costs they face?
• Customer Price/Bill Stability: Do utility customers experience relatively stable electricity distribution bills, either as a result of stable prices or by operation of a regulatory framework that manages costs over time to produce stable bills?
The report ultimately presents two perspectives on the pricing models (see Section VI). While there is a great deal of consensus among the authors about the overall framework by which DERs should be evaluated and the options available for pricing of services to and from DER customers, there is not consensus on which framework provides the best balance of efficiency, equity, customer satisfaction, and stability for utilities and consumers. Ryan Hledik presents considerations from the perspective of the distribution utility, while Jim Lazar presents issues from the perspective of consumers. Their perspectives are distinct from one another and from their clients and should not be perceived to represent the viewpoint of any of their individual clients, their employer, Lawrence Berkeley National Laboratory or the U.S. Department of Energy. These views are intended to stimulate critical examination of emerging issues, to bring creative perspectives to a complex and rapidly evolving field, and to tee up issues for future study. The time-constrained reader may wish to concentrate on Section VI of the report.
The report concludes with recommendations for exploring ideas presented through field pilot testing and rigorous analysis. In a world of rapidly emerging technologies, challenging environmental constraints, evolving consumer preferences and political realities, these pilot efforts must produce useful data and replicable results and be carefully designed, faithfully executed and professionally evaluated…
What Are Distributed Energy Resources?
DERs are any resources or activities at or near customer loads that generate energy or reduce energy consumption. They include generation technologies such as solar PV systems and emergency backup generators, energy storage such as batteries, energy efficiency, and smart appliances or other controllable loads. DERs are central to the visions that many have for an overall smart grid evolution.
Some forms of DERs are dispatchable by the system operator, while others are not. For example, virtually all forms of energy efficiency are not dispatchable because they are essentially always “on.” To illustrate, a more efficient motor will always be more efficient any time it is in use, and space heating and cooling systems will consistently consume less total energy over the course of a day after the building envelope has been better insulated.
Likewise, solar PV, absent associated storage capacity, will produce energy when the sun shines but not otherwise, and the system operator has no control over its availability. On the other hand, smart appliances like a GIWH, battery systems and air-conditioning thermal storage can be directly controlled by the system operator (or a third party) and brought “online” (in a resource sense) by turning off the heating element, discharging the battery or drawing down the “chill” stored in water reserves, or taken “off line” by turning on the heating element, charging the battery or chilling water for later use.
While DERs can be viewed as energy resources used to balance the system in real time, they can also be viewed as capacity resources used in the planning process and to maintain reliability by assuring that loads will not exceed supply during the system peak. In addition, some types of DERs can provide ancillary services, such as voltage support and frequency control and other services, and do so at extremely low cost and higher efficiency than traditional supply-side options. At the same time, DERs, particularly those that inject power to the grid and are intermittent in nature, could potentially increase system costs if they are not coupled with technologies that allow for the management of their energy supply. Power quality issues may also need to be addressed as customer loads become more variable. This may be easiest where customer loads and resources can be controlled automatically by the customer and, with permission, the utility or a third party.
Some forms of traditional central-station generation have limited flexibility from a system operator’s perspective. Nuclear- and coal-fired steam generating plants are viewed as baseload resources. The combination of their economic characteristics (high capital cost, low fuel cost) and operational characteristics (not easily ramped up or down, long lead times to come online from a dead stop) means they are most efficiently utilized when run full-out all the time. Natural gas turbines, on the other hand, have relatively low capital costs and higher fuel costs compared to baseload power plants and can be brought online quickly. They are typically used to serve on-peak demand, running a limited number of hours. Hydroelectric power has high capital costs and low fuel costs, but usually a limited “fuel” supply due to limited water availability. Most hydro projects with lakes or reservoirs operate at relatively low capacity factors, with the limited water supply used to produce power when it is most valuable. Hydro can be brought online quickly and ramped up and down easily. It is often utilized to follow changes in load or to bridge periods when steam generation is being ramped up or down.
Some DERs also can be very flexible. Because DERs come in a variety of forms, and each form comes in relatively small increments (see Table 1), it may be possible to aggregate a variety of DERs into a virtual energy resource that can match system balancing needs more closely than traditional generating resources. For example, aggregated GIWHs could be matched with PV supplies and energy storage systems (battery and thermal) to potentially provide a more stable supply of and demand for energy over the course of a day. When a passing cloud reduces PV output, water heaters could be cycled off to match the decline in PV energy, resulting in a combined resource with constant impact on the system over time…
Transitioning To Residential Demand Charges
Residential demand charges have recently been discussed as an attractive approach to pricing certain distribution services, such as the reservation of capacity on distribution substations or local transformers. A demand charge would recover some portion of the utility’s costs through a price that is based on a measure of the customer’s maximum instantaneous demand for electricity (kilowatts) rather than on his or her total monthly consumption (kilowatt-hours). There are a variety of ways in which “maximum demand” could be defined for the purposes of billing a demand charge, such as maximum demand during a period that is coincident with the system peak, maximum demand during a period that is coincident with the customer class peak, or maximum demand based on the customer’s own peak over the course of the month.
The potential benefits of this approach are numerous if the demand charge is well-designed and carefully implemented. It would improve fairness and equity in cost recovery, by reflecting the peak demand-driven nature of distribution capacity investment. It would also provide an incentive for customers to improve their load factors and for the adoption of emerging energy management technologies such as battery storage and smart appliances. With a well-designed rate, the resulting changes in electricity consumption patterns would reduce system resource costs and customer bills in the long run. And while there are certainly differences between residential and commercial and industrial customers, a practical advantage is that there is already a regulatory precedent for demand charges, which have been offered to commercial and industrial customers for decades.
Stakeholder concerns about demand charges should be carefully considered and addressed when designing a new pricing model that includes a demand charge. Many consumer advocates are concerned about bill impacts for low-income customers. Bills under the new rate design should be simulated for a representative distribution of customers in each relevant customer segment and, if certain vulnerable customer groups would see bill increases, transition strategies and tools can be developed to ease this burden. Other stakeholders have expressed a concern that demand charges do not accurately reflect costs due to the diverse nature of residential loads. A broad range of possible demand charge designs should be considered to address this concern (for example, if stakeholders are concerned that a demand charge that is based on an individual customer’s maximum billing demand is not cost-reflective, measurement of demand could instead be constrained to a peak period). Another concern is that customers cannot understand a demand charge. This can be addressed through market research that is designed to determine the simple educational messages that best resonate with customers (e.g., “avoid using many appliances at the same time in order to save money on your bill”).
Demand charges present a practical and equitable opportunity to improve residential distribution rate design where the necessary metering infrastructure is in place. Successfully transitioning to this new rate structure will require additional research and close coordination with industry stakeholders who present a broad range of perspectives on the topic…
Conclusions and Recommendations
The rapidly changing market for DERs — and the needs of utilities, consumers and the industry producing equipment for the DER market — demand that careful attention be given to pricing issues. Utility regulators are faced with yet another task that expands their scope of inquiry and influence.
The best approaches cannot be predicted with certainty. Carefully designed pilot programs and adequately funded evaluation efforts will be needed to ascertain which approaches meet the needs of all participants.
These pilot efforts fall into several broad categories:
• Gather stakeholder input. Regulators may need to convene generic dockets or rulemaking proceedings in order to invite input and comment from all affected parties. No one can predict all of the relevant issues for every DER technology, and those technologies are changing rapidly. The timing of these proceedings will depend on the ripeness of issues in each jurisdiction, with those jurisdictions experiencing rapid deployment of DERs needing to move quickly. • Conduct market research. Market research will be needed to assess customer understanding and acceptance of the pricing models. Identifying educational messages that resonate with customers will inform the design of the models and maximize customer acceptance. Market research will also inform what services consumers are willing to provide, what alternatives they are willing to consider in system design and operation, and what essential values they are unwilling to compromise. Evaluating existing complex rate designs for the level of customer understanding will provide some guidance. Working with manufacturers and vendors of DERs that are now marketing their products will provide insights into what messages resonate with consumers, and what values they ascribe to DERs that they are now acquiring. • Quantify the cost and value of distribution services that would occur in an environment of high DER adoption. Distribution costs and savings will vary by utility. They can represent a large share of the customer’s bill in some jurisdictions and a lower share in other jurisdictions. There is also the question of how much of the distribution cost can be avoided through provision of distribution services by DERs and how this compares to other sources of value, such as the avoidance of generation capacity and fuel costs. Quantitative analysis of the magnitude of the opportunity will help to shape future pricing initiatives. • Implement pricing pilots. Location and technology-specific pricing pilots must test how customers, third-party aggregators and equipment suppliers respond to the new pricing models. Effectiveness of the models in facilitating meaningful load reductions can be demonstrated through pricing pilots. Such pilots also will allow the models to be tested and refined in a controlled setting with a limited number of customers before they are considered for deployment on a full-scale basis. It may be desirable to implement these pilots in a broader geographic area than a single utility or regulatory boundary, because in addition to distribution system impacts, many DERs provide benefits best measured at a regional level — at the independent system operator/regional transmission operator level or multi-utility control area. Such pilots would need to be coordinated between one or more state regulators and the regional market operator. • Assess power supply impacts. Pilots can examine the interaction of DER impacts on the power supply system with DER impacts on the distribution system — for example, changes to peak load, system dispatch and air emissions. This report addresses only distribution system pricing issues, not the potentially much larger impacts of DERs on bulk power supply markets. • Determine if certain broad categories of distribution services or ancillary services can be most economically provided through the use of DERs. Studies can be undertaken to measure the economic savings and environmental impacts associated with a shift from traditional infrastructure to DERs providing certain distribution system and ancillary services. In particular, this report highlights certain ancillary services that may be provided at lower cost with DERs than with conventional supply options. This is another area where the impacts of DERs go far beyond the distribution system services addressed by this report.
Pragmatically, there is a role for federal coordination or national scope for at least a portion of this broad research agenda, so that redundant experimentation is avoided and research gaps are not inadvertently created. Some geographic areas, where DER deployment is already rapid, may be the best locations for an initial research agenda to proceed. Hawaii and California, with high levels of deployment of distributed PV, are two obvious examples.
Regions with little DER deployment also provide useful laboratories for testing ideas that have not yet germinated in the marketplace but provide significant promise. For instance, the Southeastern states, with the highest penetration of electric water heaters in the nation and a large air-conditioning load, may be an ideal laboratory for testing the services that GIWH and storage can provide to the grid. The Pacific Northwest, also with a high penetration of electric water heaters, a consumer base with a long history of energy awareness, and growing renewable energy integration needs, could also be an attractive market for this type of research. Ultimately, it will be important to tailor the pilots to regional needs and resources.
For each pilot we recommend that an evaluation oversight panel be comprised of technical experts, utilities, consumer advocates, environmental specialists and regulators. With all of these perspectives represented, the risk of designing an approach that “won’t work” or “won’t fly” will be minimized.
DERs are being deployed at a rapidly growing rate. The value of the services that DERs offer and the additional costs that they may introduce are not fully reflected in existing pricing models. The pricing of services to and from DERs will dictate the economics of future deployment. Now is the time to begin the transition to improved pricing models. Well-designed research and policy development will ensure that the industry is able to fully capture these new opportunities.