Chapter 20
The Repurposed Distribution Utility: Roadmaps to Getting There
Philip Q. Hanser
Kai E. Van Horn The Brattle Group, Cambridge, MA, United States of America
Abstract
This chapter discusses the decisions utilities face as they consider a transformation into the Repurposed Distribution Utility (RDU). While the RDU and its various incarnations have been widely heralded as the distribution utility’s future, there has been scant discussion about how the distribution utility in its current state can begin to make the transformation. The authors explore the challenges utility planners face when integrating distributed energy resources and the planning and operational changes required to make the RDU transition. Furthermore, they present recent examples of planning and operational changes from utilities in the midst of the RDU transition.
Keywords
distribution expansion planning
DER integration
PV impacts on distribution systems
DER distribution system impacts
1. Introduction
The era of the distributed energy resource (DER) has begun for the electric utility industry.1 Steeply declining costs for DERs, such as solar photovoltaic (PV) generation, continued development of localized storage, and regulatory incentives promoting DER expansion all have resulted in substantial investments in distribution-level DER installations over the previous decade (Barbose et al., 2014). Indeed, nearly 8 GW of PV capacity was installed on distribution systems in the United States between 2008 and 2014, representing 45% of total installed PV capacity over the same period.2
The dawning of this new era brings with it unprecedented challenges to the distribution utility’s conventional role to provide on-demand access to electricity for customers in their service territory, at a level of reliability consistent with existing standards.3,4,5 Moreover, existing utility infrastructure and operating practices reflect the expectation of unidirectional electricity flows from generators on the transmission system to end-use customers on the distribution system.6
The distribution utility structure of today will not be adequate to address the DER integration challenges faced by the industry. To address these challenges effectively, and maximize the benefits of DER integration, today’s distribution utilities must be repurposed—transitioning to become what we will call the repurposed distribution utility (RDU).7
This chapter explores the RDU transition from the frontline perspective of a utility planner faced with the daunting task of planning system upgrades and operational changes to accommodate the large-scale expansion of DERs on their distribution system—from conceptualizing the problem, to planning the RDU transition. Furthermore, using examples from California and Hawaii, this chapter delves into the approaches utilities are taking to integrate DERs that not only minimizes their potential negative impacts, but also maximizes their benefits.
Although the concentration of this chapter is on the decisions that must be made by distribution utilities to determine and plan their RDU transition needs, this assessment may also be an opportunity for distribution utilities to consider how to increase their resilience in the face of natural and cyber threats. Furthermore, though beyond the scope of this chapter, it must be noted that utility business model and rate design are important components of DER value maximization.8
The remaining sections of this chapter are organized as follows. Section 2 presents a brief review of the current situation for utilities. Section 3 provides an overview of the issues utilities face when making the RDU transition. Section 4 describes the changes to system planning required to meet RDU objectives and integrate DERs. Section 5 discusses in depth needed RDU operations reforms. The final section presents the chapter’s conclusions.
2. The current situation
Existing utility infrastructure and operating practices reflect the expectation of unidirectional electricity flows from generators on the transmission system to end-use customers on the distribution system. The expansion of DERs in systems with high adoption rates, such as those of utilities in California and Hawaii, is beginning to undermine this expectation and cause, or exacerbate, a number of reliability and quality of service issues ranging from: (1) somewhat minor issues, such as voltage flicker and excessive switching of conventional discrete voltage regulation devices, which may lead to shortened equipment lifespan; to (2) major issues that may compromise reliability and safety, such as the failure of protection schemes to operate as designed, steady-state voltage violations, reverse electricity flows, and thermal overloads, and compromised system stability.9
On the other hand, DERs present opportunities for greater local control and benefits such as reduced peak loading and distribution losses, as well increased resiliency due to locally available supply.10,11 However, the magnitude of the benefits realized is contingent on the manner in which utilities integrate DERs into their systems—existing system structures and conventional approaches to planning and operations will not harvest the majority of the benefits.
The distribution utility structure of today will not be adequate to address the DER integration challenges faced by the industry. To address these challenges effectively, and maximize the benefits of DER integration, today’s distribution utilities must be repurposed—transitioning to become what we will call the repurposed distribution utility (RDU).
The primary objective of the RDU is to maximize the value of distribution-level resources for ratepayers, while meeting reliability mandates. The RDU is similar to, but distinct from, the much talked-about distribution services platform provider (DSPP).12 While the DSPP demands a complete divergence from the conventional role of the distribution utility, the RDU is the next step for utilities along the path toward the DSPP.
The RDU is built upon the infrastructure and operating practices of the present electric distribution utility. However, the RDU harnesses, to a much greater extent than current distribution utilities, the additional flexibility and adaptability that are facilitated by system-wide data collection and data-driven control algorithms, extensive two-way communication, and automatic control.13 More importantly, in the context of this chapter, the RDU planners and operators view DERs as a resource whose benefits can be harnessed, rather than threat to be minimized and adopt planning and operational practices to support this view.
While steps are currently being taken by many distribution utilities toward becoming RDUs, such steps have not typically been part of a comprehensive push to make the RDU transition based on a detailed evaluation of the investment alternatives that will enable utilities to meet their mandate moving forward.14 To make the RDU transition, utilities will be required, in many cases, to undertake substantial investments in new infrastructure, and significant operational reforms, which may result in significant transition costs. These investments can be made more efficiently if their economic and reliability impacts are considered, to the extent possible, in a common framework, rather than as piecemeal upgrades to address immediate problems.
Thus, there loom key questions that utilities continue to grapple with: how can a utility planner assess the individual needs of their system regarding investments in infrastructure and updated operational practices to make the transition from conventional distribution utility to RDU?
3. Framing the RDU transition
RDU transition needs are specific to each utility and depend on the physical configuration of a utility’s distribution feeders and the status of their equipment, as well as their operational practices. Thus, conceptualizing the requirement of an individual utility to make the RDU transition begins with a planner assessing the status of existing utility infrastructure and current operational practices—a system overview. The goal of such an assessment is to identify the unique characteristics of a utility’s system and operational practices that impact the system’s ability to integrate DERs, the so-called “hosting capacity,”15 (eg, length of feeders, vintage of existing equipment).
A system overview helps the planner identify shortcomings of system infrastructure and operational practices, with respect to DER integration and the RDU’s value maximization objective that must be addressed in the planning phase. Such an assessment may take the form of a survey, or series of questions, the answers to which can then be used to guide the planners when selecting infrastructure investments and operational reforms for detailed analysis. The information required for the system overview will come primarily from utility planning data and operating manuals.
An example system overview survey is given in Fig. 20.1. Key system characteristics relevant to the RDU transition are given on the left, and the extent of their presence can be assessed with a rating of one to three, on the right. The shading in the background indicates the relative impact each characteristic tends to have on system holding capacity, all else being equal (Black & Veatch, 2013; Navigant Consulting, 2013; Broderick et al., 2013). While this list is by no means exhaustive, it captures many of the key considerations relevant to the RDU transition.
Figure 20.1 Key RDU transition system characteristics.
A “short” feeder is typically one that is less than 5 miles in length; load density refers to the total load on the feeder divided by the geographic area encompassed by the feeder; and the voltage drop under peak load conditions measures the voltage drop across the length of the feeder and is an estimate of the proximity of the system to its voltage limits. The thermal capacity should be considered with respect to peak loading conditions. A classification of “high” indicates that substantial additional thermal capacity remains under peak load conditions, for example, 50% of total capacity.
A “short” feeder is typically one that is less than 5 miles in length; load density refers to the total load on the feeder divided by the geographic area encompassed by the feeder; and the voltage drop under peak load conditions measures the voltage drop across the length of the feeder and is an estimate of the proximity of the system to its voltage limits. The thermal capacity should be considered with respect to peak loading conditions. A classification of “high” indicates that substantial additional thermal capacity remains under peak load conditions, for example, 50% of total capacity.
An effective system overview will identify the distribution utility characteristics likely to have the highest impact on DER hosting capacity, and thus should receive more focus in subsequent planning activities. The system overview also points out where the current system infrastructure and operating practices may fail to align with the requirements of the RDU. These aspects can be divided into three primary and interrelated areas:
1. Inadequate physical infrastructure; for example, radial feeders with protection schemes geared toward electricity flows from substation to customer, but not vice versa;
2. Insufficient communication, measurement, and control infrastructure; for example, a lack of high-granularity measurements devices, such as microphasor measurement units, two-way communication, and control systems; and
3. Insufficient operational procedures; for example, little, if any, active control of loads and DERs, insufficient protection schemes for two-way flows, and few data-driven, automated operational procedures, such as online line health monitoring and dynamic rating of distribution lines/transformers.
Once the planner has broadly assessed the current status of system infrastructure and operational practices to achieve the RDU objective, the next step is to assess in a more detailed fashion the additional infrastructure and operational practices that will be required to overcome any barriers to meeting that objective. Doing so requires an expanded approach to conventional planning and operations.
4. Planning the RDU transition
As described earlier, the goal of the RDU planner is to maximize the value of system resources for ratepayers while ensuring safe and reliable access to the distribution grid. Thus, when facing the expansion of their system in the presence of rapid DER deployment, the primary goals of RDU planners include the foundational goals of conventional distribution system planning: to ensure reliable, safe, and efficient access to electricity for consumers in the utility’s service territory. However, the scope of these goals must be broadened, such that they apply not only to electricity consumption by end-use consumers, but also to production and other services provided by DERs.16
Moreover, the variability and uncertainty associated with DERs requires planners to expand the scope of conventional planning considerations, and demands updated planning approaches and tools. While planning with DERs is undeniably a more complicated undertaking than conventional planning, there are commonalities between conventional and DER-inclusive planning that enable the systematic assessment of DER-driven needs, and that reduce the burden on planners to invent an entirely new approach. Furthermore, as discussed later, the experience of “first adopters,” such as the utilities in Hawaii and California, can act as a road map for other utilities seeking to plan their RDU transition.
Conventional utility distribution system planning is rooted in the steady-state analysis of the distribution system under forecast future peak load conditions.17 Utility planners, using conventional planning tools such as power flow analysis, have typically assessed: (1) the adequacy of physical infrastructure to reliably meet future energy delivery and system security needs18; and (2) candidate upgrades to existing infrastructure in the event existing infrastructure is found to be inadequate.19 A number of such candidate investments are evaluated and those deemed to yield the lowest costs for ratepayers, while meeting the reliability needs of the future system are selected for investment.
While planning the RDU transition requires the assessment of (1) and (2) above, DERs complicate the process due to the uncertainty associated with their capacity, location, and the amount of power and energy they will produce, and the resulting impacts on power quality and voltage. These complications require additional planning processes, discussed next, that complement and expand the conventional approach. Furthermore, they require the assessment of current operational practices to determine where changes in operational practice may substitute for—or complement—infrastructure investment, in order to maximize the benefits of DER integration.
4.1. DER Expansion Forecast
A new and demanding task associated with planning the system for widespread DERs is DER expansion forecasting. A DER expansion forecast consists of forecasting, at a desired future point in time, the type and quantity, a single value or range, of DERs the utility anticipates coming onto the system, and the locations of those DERs. For many systems, such as those with long or thermally/voltage-constrained feeders, DER location is particularly important in determining the overall transition cost.
The DER expansion forecast may consist of a sophisticated forecast of future DER installations, if the data required for such an undertaking is available.20 If the construction of such a forecast is not possible or not desired, the DER forecast may also consist of a set of potential DER growth scenarios against which the performance of the system can be assessed to “book end” the range of potential RDU needs. For example, a forecast may include two DER growth scenarios: a worst-case scenario in which DERs are highly concentrated far from the head of feeders, and a best-case scenario in which DERs are distributed more evenly along feeders, or at their strongest points of interconnection.
The use of scenario-based analysis for a multitude of forecast future DER growth scenarios is emerging as the primary methodology for assessing the diversity of system conditions distribution equipment will face with deep DER penetrations. For example, the California investor owned utilities (IOUs) were recently tasked with the development of Distribution Resource Plans, a key component of which is the production of a set of DER growth scenarios.21 These scenarios define the potential future realizations of DERs against which the IOUs will assess the costs and benefits of DER integration, and plan their systems.
4.2. Planning Infrastructure to Maximize DER Value
Achieving the RDU value maximization objective requires planning tools that can assess the physical limitations of the system with respect to DER integration, as well as those capable of determining the various benefits of DER integration, and the system upgrades that maximize those benefits. These planning requirements are an extension of those used in conventional planning processes, which focused primarily on assessing cost and reliability of service. Table 20.1 compares conventional and RDU planning.
Table 20.1
Comparison of Conventional and RDU Planning
| Aspect | Conventional planning | RDU planning |
| Time frame | Few snapshots | Time series analysis |
| Time granularity | Single hour periods associated with snapshots | Multiple simulation periods used to assess different levels of variability, for example, hourly for net load ramping, minute-by-minute for short-term voltage fluctuations driven by PV |
| Number of planning scenarios | Limited to peak load and a few high impact contingency scenarios | Deployment of numerous scenarios for forecast DERs and net load |
| System protection assessment | Assess for one-way flows | Assess for variable, two-way flows |
| Voltage equipment assessment | Assess for one-way flows | Assess for variable, two-way flows |
| Dynamic stability analysis | Limited use of dynamic simulations | Feeder-level dynamic simulations required for feeders with wide-spread DERs |
| DER hosting capacity analysis | None | Foundation of RDU planning |
| Location-specific resource costs/benefits assessment | None | Key for assessing value maximization objective |
| Assessment of operations solutions to infrastructure deficiencies | Little to none | Extensive |
Physical infrastructure limitations to DER integration come in the form of: (1) inadequate thermal capacity of lines and transformers; (2) failure of the protection system to operate as designed; and (3) the emergence of voltage issues, such as flicker and steady-state voltage violations. Determining the extent to which each of these limitations exist in a particular system can be done with conventional power flow based tools. However, it requires planners to diverge from the conventional planning practice of assessing a few scenarios, or snapshots, of system operation, such as peak loading conditions.
Instead, the planner must expand the number of scenarios they consider to account for the DER expansion forecast scenarios. In addition, the focus in conventional planning on a few points in time, for example, the peak load hour, must give way to time series analysis to capture the impacts on the thermal capacity, protection systems, and voltage of period-to-period DER variability. The most challenging operating conditions with high levels of DER may not coincide with the peak load period, and this will be revealed through such time series analysis. Table 20.1 compares conventional and RDU planning.
Additionally, voltage regulation and protection equipment must be analyzed with respect to the higher variability in distribution line flow magnitude and direction. Present voltage control equipment is switched on time scales, on the order of minutes to hours, whereas DERs, such as solar, PV may cause voltage fluctuations on much shorter time scales (eg, seconds to minutes). Therefore, it may be necessary to perform power flow simulations for select periods on these shorter time scales, so as to assess the impacts of voltage control investments on smoothing out DER-driven voltage variability. Such variability will also necessitate the analysis of many additional fault scenarios in system protection studies, and require new models for DERs to capture their fault response adequately.
The existence of controllable equipment, such as generators and fast-regulating voltage equipment, on the distribution system will also require additional dynamic stability simulation in the planning process. However, in many cases, new dynamic models will be required for distribution-level devices. Such models will emerge from collaborations between device manufacturers, utilities, and the academic community.
The extent of the system limitations to DER integration and the benefits of DER integration are highly dependent on the location of the DERs in the system. For example, DERs located near the substation may be less effective at reducing distribution-level losses than DERs located further down the feeder or closer to the loads, or the DER hosting capacity of individual buses may differ along the feeder. Therefore, to harness DERs efficiently, it is necessary for planners to assess their locational costs and benefits. The deployment of time series-based power flow simulation of distribution feeders enables such analysis.
Value maximizing planning also requires planners to not only expand the tools they use to plan the system, but also the set of potential candidate investments to address the infrastructure needs identified during the planning process. For example, the most prudent approach to alleviating a voltage limitation that may restrict severely the DER hosting capacity of a feeder may be the installation of fast-acting voltage regulators, along with measurement and control infrastructure to enable advanced control. Furthermore, to address identified limitations efficiently, it may be necessary for planners to consider additional substations installations, as well as unconventional approaches such as more meshed topologies, distribution system interconnections, and neighborhood-level energy storage technologies.
4.3. Recent Developments in Advanced Distribution Planning
The rapid growth of DERs in Hawaii and California has prompted regulators and utilities to reevaluate distribution planning processes. The experience from the utilities in these states sheds light on some potential approaches to addressing the needs of the RDU transition, and, in particular, the integration of DERs into planning, so as maximize their value to the ratepayers.
As described earlier, evaluating the hosting capacity of a distribution feeder is one of the major challenges brought by DERs to distribution planning. To address this challenge, the California IOUs22 have proposed a process termed Integrated Capacity Analysis (ICA), deployed in parallel with conventional planning processes (SDG&E, 2015; SCE, 2015; PG&E, 2015). The goal of ICA is to identify the hosting capacity of a distribution circuit, with respect to four limitation categories: (1) thermal ratings; (2) protection system limits; (3) power quality standards; and (4) safety standards. Feeder circuits are analyzed by breaking them into zones or line sections, typically four for a single distribution circuit. DER capacity is added to each zone or section individually, until one of the limits is reached.
Furthermore, the California IOUs have proposed an Optimal Location Net Benefits Methodology (LNBM) intended to assess the locational aspects of DER placement, and identify locations at which DER deployment is a viable substitute for conventional distribution investments (SDG&E, 2015; SCE, 2015; PG&E, 2015).
The Hawaiian utilities23 have also been grappling with a flood of DER development, which has pushed them to develop new planning approaches. To this end, the Hawaiian utilities have proposed their own approach to integrating DER considerations into their distribution planning framework. The primary tool they proposed is the Distributed Generation Interconnection Capacity Analysis (DGICA), a “process for proactively identifying distribution system upgrades needed to safely and reliably interconnect DG resources and increase circuit interconnection capability in capacity increments” (Hawaiian Electric, 2014). In a similar fashion to the ICA proposed in California, the DGICA outlines an approach to assessing the hosting capacity of distribution circuits, so that distribution planners prevent inadequate consideration of DER integration in planning from becoming a barrier to DER interconnection. Furthermore, Hawaii’s utilities propose to modify the distribution circuit design criteria to facilitate increases in hosting capacity (Hawaiian Electric, 2014). The following additional criteria were proposed: (1) lowering impedance; (2) optimizing reverse flow on voltage regulation equipment; and (3) mitigating circuit-level transient overvoltage.
In both the California and Hawaiian cases, the need for time series-based power flow analysis, and more extensive scenarios of future system conditions, was explicitly acknowledged. Moreover, the utilities in these states, such as Pacific Gas and Electric Company in northern California, have made strides in incorporating such analysis into their existing planning framework, and provide examples for other utilities looking to follow a similar path (PG&E, 2015).
5. RDU transition operational practice reforms
Operations is perhaps the largest area in which utility practices will change as a result of the RDU transition. Due to the historical structure of the distribution system as a conduit for one-way flows from the substation to end-use consumers, the operation of the system has largely been passive in nature. What little controllable equipment has been present on the system, for example, switched capacitors or tap-changing transformers, was operated according to schedules or forecast system conditions, rather than according to real-time measurements and needs. Such an approach was reasonable and effective when the operator’s goal was to meet a relatively predictable load reliably, and maintain voltages within specification. With DERs in the mix, however, such a passive approach is no longer tenable.
The RDU takes an active approach to operations in which it aims to maximize the value of DERs by fully utilizing advanced measurement, communication, and control infrastructure, as well as harnessing the control of DERs to shape the load and control voltage, among other objectives. Making this transition from passive to active operations will require additional measurement collection and control equipment, as well as changes in operating practices, all the way down to the energy management system (EMS) functionality. Table 20.2 gives a comparison of conventional and RDU operations.
Table 20.2
Comparison of Conventional and RDU Operations
| Aspect | Conventional operations | RDU operations |
| Control objective | Serve end-use consumer, maintain voltage within specifications | Maximize DER value to rate payers while meeting reliability criteria |
| Use of measurements (system visibility) | Limited SCADA data collected at substations and advanced metering infrastructure (AMI) | Extensive measurement collection throughout system |
| Level of automation | Some automated breaker operation | Widespread distribution system automation and use of automatic DER control |
| Use of data-driven algorithms | Little to none | Algorithms become the cornerstone of operations |
| Two-way communication with resources | Modest, largely communication with loads via AMI | Ubiquitous two-way communications between operator and resources |
The collection and use of high bandwidth, time-stamped measurements using equipment such as AMI, microphasor measurement units (PMUs) (Micro-Synchrophasors Project, 2015), or line-mounted sensors (Tollgrade Communications, 2015), will be the bedrock of this transition. The RDU will require a measurement system that has sufficient: (1) measurement granularity, for example, are measurements collected every hour, minute, or even more frequently, and do these align with the operational needs; (2) measurement coverage, for example, are the key distribution buses equipped with voltage measurement devices; and (3) measurement type, for example, are sufficient voltage measurements being collected to enable advanced control. Furthermore, with extensive measurement collection, the capability will exist for data-driven analytics, such as online infrastructure health monitoring and DER dispatch, which will become a cornerstone of RDU operations.24
The deployment of measurement equipment throughout the system will present additional control opportunities for the system operator. However, to implement advanced control successfully, the RDU will require two-way communication with resources in the system to enable utility operators to collect data from devices in the system, and to send control signals to achieve desired operational objectives. While some two-way communication equipment, mainly AMI, has been installed in distribution systems, the rollout of such communication equipment must be broadened from AMI, and those resources participating in demand response programs, to a larger set of resources, including all new and existing DERs.
5.1. Recent Developments in Advanced Distribution Operations
Operational reforms have been a large part of the DER integration discussion taking place in California and Hawaii. In both states, utilities have proposed operational reforms to facilitate higher DER penetrations, as well as pilot projects to test the effectiveness of the proposed reforms.
Southern California Edison, for example, has proposed a pilot project to “test its current operational capabilities and those capabilities that are needed to coordinate third-party DER and potentially utility-owned DER.” Furthermore, “the technology infrastructure (eg, telecommunications, monitoring devices, and control systems) to be deployed in the area are aimed at providing additional capabilities (eg, monitoring, controls) that may enable coordination of higher levels of penetration throughout the SCE system.”25 Such pilot projects will reveal the extent to which utility operations must shift in order to enable the effective integration of DERs.
The Hawaiian utilities have been more explicit in defining operational reforms to facilitate DER integration. In their Distributed Generation Interconnection Plan (Hawaiian Electric, 2014), the utilities propose the following operational practice changes:
• Operating within voltage regulation bands
• Maintaining distribution circuit flexibility
• Lengthening reclosing time of feeder breakers and reclosers for islanding protection
• Monitoring voltage regulator tap operations
• Implementing SCADA at distribution substations
The Hawaiian proposal makes clear the need for a fundamental reassessment of distribution operations, with respect to increasing DER deployment. The proposal of basic reforms, such as the implementation of SCADA at substations, also sheds light on the long distance left for utilities to travel in order to complete the RDU transition.
6. Conclusions
All utilities will undertake the RDU transition, to some degree, the extent of their transition depending largely on the level of DER integration that will be required in their service area. While some steps have been taken by utilities in California and Hawaii toward making the RDU transition, there has been little experience so far with advanced planning and operations processes, so there is not yet a consensus on the “best practices.”
This chapter presents an approach to conceptualizing and planning the RDU transition that enables planners to address DER integration, in a way that aims to maximize value for ratepayers. However, in any foreseeable future, the conditions under which utilities operate are rapidly evolving. Ultimately, it is up to individual distribution utilities to assess how they can adapt to their unique conditions best. The uniqueness of their conditions, however, does not preclude them from taking a systemized approach to determining their needs. In fact, such an approach is both achievable and necessary to build highly complex distribution systems whose operation ensures, economically and reliably, access to electricity for consumers and producers alike.
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