Part 2: Key choices on the way forward.
Sonia Aggarwal is the Director of Strategy at Energy Innovation: Policy and Technology LLC, where she works on policies to transform the electric grid and reduce emissions. Robbie Orvis is a policy analyst for Energy Innovation’s Smart Energy Policy program area. Michael O’Boyle works as a policy analyst for Energy Innovation’s Power Sector Transformation area. The authors thank Kurt Adelberger (Google), Katherine Hamilton (Energy Storage Association), Devra Wang (Natural Resources Defense Council), Eric Gimon (independent consultant), and Hal Harvey (CEO, Energy Innovation), for their valuable insight.
In last month's issue and in the first part of this series, we reported how advances in technology in the electric utility industry have outpaced both markets and rules, inviting a new look at how we operate the distribution side of the grid. In some ways, it's a replay of the 1970s and 1980s, when a revolution in cogeneration and small power production upset long-held notions and led eventually to restructuring in transmission and wholesale power - a restructuring that introduced regional grid operators (RTOs and ISOs) and bid-based regional power markets.
During those prior decades, utilities came face-to-face with competition from new actors, forcing costs up even as revenues were falling. This influx of new actors exposed the need for smart long-term transmission planning and impartial short-term transmission system operators.
Today, as then, the distribution system faces some similar market conditions. Rising utility costs coupled with falling sales because of the emergence of distributed energy resources (DERs), particularly energy efficiency and rooftop solar, have led to rising retail rates, falling revenues, and cries of a new "death spiral" (the same term used in the 80s).1 In some situations, DERs can provide services more cost-effectively than traditional utility assets. But their adoption has met resistance from many utilities, that see them as a threat.
New technological advancements, like battery storage, home automation, and distributed generation offer competitive alternatives to the conventional model of utility-controlled one-way distribution.2 Consumers have more options than ever to provide on-site grid services that complement or even replace much of their electricity needs, sometimes at a much lower cost than conventional electricity. Between smart thermostats, home automation, distributed solar, price-responsive demand, and electric vehicles, the list of distributed energy resources continues to expand. In concert, these DERs provide customers with more and more options to displace utility electricity service.3
An optimized distribution system could integrate DERs with existing centralized resources to maximize public benefits, e.g., by reducing investment needs and operating costs of electricity delivery, improving system reliability and resilience, supporting achievement of a state's energy efficiency and clean energy goals, reducing peak demand, and improving the overall system load factor.4 For each type of electricity service, an optimized system weighs all resources - demand- and supply-side - and uncovers the least-cost portfolio of resources to deliver customer value.
Figure 1 - Distribution Optimization
An optimized system also could identify the locational value of important grid services and help fulfill them efficiently, using a smart set of centralized resources, infrastructure, and DERs with the aim of lowering overall costs, improving reliability, and meeting other state policy goals.5
Several states, most notably California and New York, have identified the profound opportunities available from DERs and have prioritized distribution system optimization. California has chosen to test a more planning-oriented approach by asking incumbent utilities to come up with integrated Distribution Resource Plans6, while New York has chosen to test a more market-oriented approach by creating a transactive distribution platform via their Reforming the Energy Vision (REV) initiative.7 It is too early to tell exactly how either approach will support an even playing field for customer-sited and centralized resources, but it is feasible that either approach can work, as long as the supporting institutions, markets, and regulatory structures are set up well.
With these ideas in mind, let's look at how we might rethink the distribution system, applying best practices learned from the restructuring of the bulk power system. This article will suggest pathways for policymakers and utilities to take advantage of new technology and past experience to move toward an optimized distribution system.
Integrated Distribution Planning
Integrated Distribution Planning (IDP) - much like its bulk power system cousin, Integrated Resource Planning (IRP) - provides a useful starting point for regulators and utilities to begin thinking about how to optimize the distribution system.
Under IDP, utilities collect information on how the existing distribution system is performing, assess how it is accommodating new DERs, evaluate how and where DERs are likely to grow, identify interconnection issues, plan for upgrades where needed, and share findings with regulators and the public.8 A well-constructed regulatory framework for IDP requires utilities to study the value of new capacity, energy, and ancillary services in different parts of the distribution system, integrating projections about how the system is likely to evolve over time. It also requires utilities to study the costs and benefits of DERs in comparison to traditional infrastructure upgrades, understanding how alternative portfolios of DERs would perform against a substation- or line-upgrade, for example, on distribution services like voltage stability or frequency regulation. Then, regulators should work with utilities to establish a plan for how to use tools like rate reform, tariffs, metering and software upgrades to maximize these benefits in concert with bulk-system resources.
Lively debates have sparked over which DER costs and which benefits should be counted and compensated. Decisions about which costs and benefits make the list are heavily influenced by the public policy objectives in a certain state or region. For example, some states count greenhouse gas reduction or air quality improvements from DERs as a benefit, while others may not. States exposed to risk of extreme weather may count resilience as an inherent value, while others may not. Other factors like local economic development or increased consumer choice may play a part. In order to undertake a productive IDP process, policymakers and regulators must make these judgements explicit at the outset, and give clear guidance on the methodology for assessing and monetizing costs and benefits.
Fortunately, new frameworks for developing cost-benefit analyses for DERs are emerging. For example, the Electric Power Research Institute (EPRI)'s Integrated Grid: A Benefit-Cost Framework9 provides a replicable methodology for utilities and regulators to analyze the costs and benefits of each type of DER in each specific situation, taking into account a broad range of costs and benefits. As new DER technologies emerge, pilot projects can help assess their capabilities, elucidating new cost-benefit methodologies appropriate for emerging technologies. Once IDPs map the locational value of electric services on the distribution grid - in terms of location-specific electricity, capacity, or other grid services like voltage control - tools like EPRI's can help regulators, utilities, and market participants get a better sense of what portfolio of DERs can best meet system needs.
Some states already have taken the first steps toward IDP. In Massachusetts, the Department of Public Utilities (MADPU) recently adopted an open stakeholder process to improve information sharing for DER interconnections.10 The goal of the MADPU's process is to improve the pace of DER interconnection and make more information publicly available.11 In California, Assembly Bill 327, enacted in 2013, requires utilities to "identify optimal locations for the deployment of distributed resources" and submit their findings in a Distribution Resources Plan proposal reviewed by the California Public Utilities Commission, beginning in July of 2015.12 As a part of the New York REV proceeding, utilities will be required to undertake Distributed System Implementation Plans (DSIPs) that will investigate and propose system upgrades and make data available to third parties to animate the market for DERs.13 Other states, including Hawaii, Maryland, New Jersey, and Delaware have undertaken some steps toward IDP as well.14 To ensure a fair assessment, IDPs should be transparent, encourage stakeholder input, and include simultaneous programs to prove the viability of new DER technologies.
Once it is clear where and when system services are needed and how costs and benefits should be counted, regulators must take a hard look at utility financial incentives to ensure that they are properly motivated to compare investments in grid infrastructure on equal footing with customer-sited - or customer-owned - DERs. Planning the system to accommodate an influx of DERs may cut into some traditional utility revenue streams, but as described in the next section, it will open new revenue streams for proactive, forward-looking utilities.
DSO as System Optimizer
Beyond an Integrated Distribution Plan, some states may choose to take the next step: to establish a Distribution System Optimizer (DSO) to facilitate transactions for distributed resources. The DSO function could be housed within the incumbent regulated utility or could be established in an independent institution. Either way, the DSO would call on available resources to meet system needs based on costs and physical constraints. In many respects, the DSO is equivalent at a distribution level to the ISO at a bulk power level.
The DSO could choose to meet local demand with a combination of distributed resources like rooftop solar, storage, or price-responsive demand, compared against transparent real-time prices from the ISO. Depending on what institutional form it takes, the DSO may also coordinate directly with the bulk-system to export electricity or services from DERs if they exceed local demand. The DSO also could act as a transactive authority for buyers and sellers to interface with one another, essentially enabling DERs to compete with wholesale electricity service.15 However, this configuration may raise the possibility of oversight from the Federal Energy Regulatory Commission (FERC) if the DSO is itself buying and selling electricity and grid services. Depending on the institutional structure, together, the ISO and DSO could facilitate interactions between wholesale and retail actors by standardizing transactions, allowing aggregation of resources, and clearing the markets accordingly.16
Alternative DSO Frameworks
The DSO framework would change the way that distribution utilities collect revenues. The DSO market structure presents new risks for incumbent distribution utilities and customers, which should be accompanied by new opportunities for growth. DERs may displace opportunities for utility investment that would traditionally be rate-based, but a well-operated distribution grid platform would provide new value to the system, opening up a possible new growth business for proactive distribution utilities.
This DSO framework could take several forms, two of which we describe below, as alternative models.
One option - championed by former FERC Chairman Jon Wellinghoff - is an Independent Distribution System Operator (IDSO), by which an independent third-pary entity would serve as the DSO and would carry out functions similar to those performed by an ISO at the transmission level, but in this case would operate a market for location-specific services on the distribution system.
Another option - currently being developed by the New York Department of Public Service - is the Distribution System Platform Provider (DSPP), which would transform the existing regulated utility into a distribution system optimizer.17 The IDSO and the DSPP would serve similar DSO functions, with the primary differences being regulatory jurisdiction and ownership of the distribution infrastructure.
An Independent Operator. Risks of market power may be greater at the distribution scale than at the bulk system scale, in part because distribution is often laid out in a radial topology (one way to get power from point A to point B) rather than a mesh topology (many ways to get power from point A to point B). To address this (and the other traditional) market power concerns, the Independent Distribution System Optimizer (IDSO) framework proposes two entities where there used to be one.
The physical distribution system would continue to be owned by a regulated utility, while a new IDSO would take on the role of a market operator and dispatcher for distributed resources, similar to the way the transmission system is operated in restructured regions. The IDSO would establish a rate or tariff structure to pay for use of the distribution network, as with the transmission network,18 and would administer a transactional market for distributed energy and services.
To address remaining market power concerns, the regulated utility that owns the distribution system would be prohibited from bidding resources into the IDSO,19 but would be compensated for its investment in the physical system via a basic cost plus rate of return model in addition to the tariffs collected from resources using the system. This is also analogous to transmission operators on the bulk transmission system, who own and maintain the transmission assets but surrender their operation to the ISO. Utility holding companies could, and likely would, engage in these competitive markets via unregulated subsidiaries or affiliates.
A Utility-Run Platform. In the Distribution System Platform Provider (DSPP) model, the distribution utility would take charge of dispatching an optimal set of centralized resources and distributed energy resources. It would own the physical distribution system itself, and would be responsible for compensating customers and third parties for the services they provide. The DSPP could either administer a market for energy and services, or it could set tariffs - differentiated by location and time.
A new set of business functions and supporting technology would be needed to operate this kind of market- or tariff-based platform. Innovative utilities are already grappling with how to develop these new platform services, and see this as a promising avenue for growth. But in order for a distribution utility to fully embrace DSPP functions, regulators must reconsider the way it earns money. The traditional earnings model, based on a regulated rate of return on capital expenditures, does not square with a DSPP role for the distribution utility. It is quite likely that optimized portfolios of innovative DERs will cost less than the traditional alternatives (see ConEd's Brooklyn Queens Demand Management Program, for example). If the DSPP's main earnings opportunity remains a regulated rate of return on capital expenditures, optimized portfolios of DERs will not pencil out as a better investments. Instead, DSPPs must have opportunities to earn revenue based on performance (or pay penalties for underperformance on distribution system optimization), rather than earning a blanket rate-of-return on capital expenditures.20 The DSPP may also augment that performance revenue with fees from providing new platform services.
Market power issues may be more acute in the DSPP setup than the IDSO setup. So, while the utility would provide basic distribution services, it would be prohibited from owning distributed energy resources that could provide value-added services because of the risk of market power (this decision was made this past spring in New York's Reforming the Energy Vision initiative).21
Choosing Between Models
Each approach - the Independent Distribution System Operator (IDSO) and the Distribution System Platform Provider (DSPP) - offers benefits and drawbacks.
Let's start with the DSPP idea. The New York State Department of Public Service staff explains: "because the DSPP core functions [are] highly integrated with utility planning and system operations, assigning them to an independent party [is] redundant, inefficient and unnecessarily costly."22 There are practical difficulties associated with separating the real-time operation of the distribution grid infrastructure from its ownership and maintenance, redundancies in data collection and analysis, and a learning curve for an independent body to learn the system and respond to its participants. An IDSO requires the creation of a new institution subject to another layer of regulatory oversight. In some states, political expediency and limited regulatory resources may favor leaving the control of the distribution grid within the incumbent utility.
Alternatively, the IDSO model, while it may be complex to implement, provides an attractive theoretical framework to enhance competition and facilitate customer choice. Separating the ownership of the distribution system from its operation removes a potential bias towards investment in traditional, utility-owned grid assets. Though the DSPP framework represents a significant shift away from the status quo, it could, without close regulatory oversight, allow utilities to exercise market power and suppress innovation at the expense of customers and market participants. An IDSO model avoids these conflicts of interest by creating an objective analog to the bulk-system ISO.
Which model for distribution system optimization is most appropriate depends on the resources available, as well as the history and preferences of each state.
But regardless of the model that is chosen, it's worthwhile to think about distributed energy resources holistically through an integrated plan. Such a plan should include a compensation structure with transparent prices for distributed grid services - a structure that can enable the grid to remain reliable and resilient while incorporating new technologies, emitting less carbon, increasing customer choice, and decreasing overall system costs.
Whether housed within the incumbent utility or an independent entity, the functions performed by a Distribution System Optimizer, could help use market forces to uncover value and make prices transparent. These transparent prices would expose the value of the services provided by distributed energy resources and by the grid itself, helping solve some of today's most challenging rate design challenges. The Distribution System Optimizer then could use these transparent prices to put together a smart portfolio of distributed assets, and to ensure that both grid owners and DER owners are compensated appropriately.
Many new technologies can already provide low cost services to the electricity grid, but they are not yet being used at scale. Smart thermostats, home automation, distributed solar, price-responsive demand, and electric vehicles can help distribution system operators maintain a reliable, affordable, and clean grid. However, our ability to take advantage of these technologies is dependent on whether we create space for them on the grid and compensate them appropriately.
Any new framework must reshape utility financial incentives to ensure a fair comparison between investments that expand utility-owned infrastructure and new customer-sited solutions that may provide the same service. Whether a state chooses to stop after integrated distribution planning or make the next step toward establishing a distribution system optimizer, one thing is clear: new technologies hitting the distribution grid offer profound opportunities, but require new ways of thinking and planning - and perhaps even new institutions - to unlock their power.
Endnotes:
1. Frank A. Felder and Rasika Athawale, "The Life and Death of the Utility Death Spiral," The Electricity Journal 27, no. 6 (2014), doi:10.1016/j.tej.2014.06.008.
2. Centralized resources refer to those connected at high-voltage nodes above the substation, and generally consist of large power plants located far from population centers.
3. Economics of Grid Defection, RMI.
4. State of New York Public Service Commission, Case 14-M-1010, Proceeding on Motion of the Commission in Regard to Reforming the Energy Vision, Order Adopting Regulatory Policy Framework and Implementation Plan, Issued and Effective Feb. 26, 2015, p. 50.
5. Other aims might include better environmental performance, increased customer choice, and local economic development.
6. See CA CPUC website on Distributed Resource Plans, URL: http://www.cpuc.ca.gov/PUC/energy/drp/.
7. See NY REV docket, URL: http://www3.dps.ny.gov/W/PSCWeb.nsf/All/26BE8A93967E604785257CC40066B91A....
8. Tim Lindl et al., Integrated Distribution Planning Concept Paper: A Proactive Approach for Accommodating High Penetrations of Distributed Generation Resources (Interstate Renewable Energy Council, Inc., 2013).
9. http://www.epri.com/Press-Releases/Pages/EPRI-Unveils-Benefit-Cost-Frame... The California PUC also has made available a software-driven "draft public tool" to identify and measure the relative costs and benefits provided by DERs - in this case, to help stakeholders design a compensation scheme to replace "net energy metering" and reward customer-sited rooftop solar photovoltaics in a way that recognizes the costs and benefits that rooftop solar imposes on the grid. (See, ALJ Ruling Seeking Comment on Draft Public Tool, CPUC Rulemaking 14-07-002, filed Apr. 15, 2015.)
10. Ibid.
11. Ibid.
12. Assem. Bill 327, 2013-2014 Reg. Sess., ch. 611, 2013 Cal. Stat. Assem. Bill 327, 2013-2014 Reg. Sess., ch. 611, 2013 Cal. Stat. Assem. Bill 327, 2013-2014 Reg. Sess., ch. 611, 2013 Cal. Stat. Assem. Bill 327, 2013-2014 Reg. Sess., ch. 611, 2013 Cal. Stat.
13. State of New York Public Service Commission, Case 14-M-1010, Proceeding on Motion of the Commission in Regard to Reforming the Energy Vision, Order Adopting Regulatory Policy Framework and Implementation Plan, Issued and Effective Feb. 26, 2015, at 32.
14. Lindl et al., Integrated Distribution Planning Concept Paper: A Proactive Approach for Accommodating High Penetrations of Distributed Generation Resources.
15. See, e.g., John Wellinghoff, James Tong, & Jenny Hu, "The 51st State of Welhuton," SEPA 51st State Challenge, February 27, 2015, URL: http://sepa51.org/submissions/submissions/Tong_Wellinghoff_Hu_51st_State....
16. While we envision DSOs primarily in regions with ISOs, the lack of an ISO does not preclude the implementation of a DSO.
17. State of New York Public Service Commission, Order Adopting Regulatory Policy Framework and Implementation Plan.
18. Wellinghoff, Hamilton, and Cramer, "Proceeding on Motion of the Commission in Regard to Reforming the Energy VIsion Case No. 14-M-0101: Comments of Jon Wellinghoff, Stoel Reives, LLC and Katerhine Hamilton and Jeffrey Cramer, 38 North Solutions, LLC.
19. Ibid. The concern is that a poles and wires utility in an IDSO setup would still control access to the distribution system, and that in order to avoid market power and discriminatory access issues, utilities would be barred from owning DERs. This is similar to what happened on the transmission system under deregulation.
20. For more detail on how to design this, see Aggarwal and Burgess, New Regulatory Models and Whited, Woolf and Napoleon, Utility Performance Incentive Mechanisms.
21. Here, the concern is that since the utility will be operating the market, if they are allowed to offer value-added services as well they have a strong incentive to choose their own resources.
22. New York Public Service Commission, Order Adopting Regulatory Policy Framework and Implementation Plan, p. 45.
See Part 1: How markets today are out of sync
The time has come to consider options for optimizing distributed energy resources, with the intent of supporting a least-cost, reliable, and clean system that delivers more choice and control for customers.
Lead image © Can Stock Photo Inc. / vencavolrab
