Restructuring Revisited Part 2: Coordination in Electricity Distribution Systems.

AuthorBurger, Scott P.

    Distributed energy resources (DERs) (1) and digital technologies dramatically expand the number of potential investors in and operators of power system infrastructure, challenging traditional means of planning and coordinating the construction of generation, storage, and network assets. Distribution-connected resources have historically not participated in traditional means of executing least cost, security-constrained dispatch of generation and typically face inefficient retail tariffs as opposed to market-determined prices. Thus, the emergence of DERs is challenging the structures historically used to coordinate investments in power system infrastructure in the medium and long term, and to coordinate supply and demand to ensure reliable operations of power systems in real time.

    During the wave of restructuring that swept through the electricity industry in the 1980s, 1990s, and 2000s, regulators established or sanctioned market constructs in order to ensure efficient pricing and the development of an efficient mix of transmission and generation assets in the short and long run (European Commission, 2009; FERC, 1999; P. L. Joskow, 1996). Today, the emergence of DERs is spurring regulators to engage in analogous debates over how to ensure the efficient utilization of and investment in both DERs and the system's conventional suite of network, generation, demand, and storage resources. Existing industry structures need to be revisited once again, to guarantee that they do adequately achieve these goals.

    This is the second paper in a two-part series that explores the implications of decentralization and digitization for competition and coordination in electricity distribution systems. Part 1 analyzes the economic characteristics of the distribution-level roles required for efficient planning and operation of the power system and the implications of these characteristics for industry structure, competition, market development, and economic efficiency. Part 2 (this paper) analyzes the pricing mechanisms and institutional arrangements needed to coordinate actions between the distribution network owners and operators, bulk power system stakeholders, DER owners, and electricity consumers.

    Efficient coordination of investments and operations of a mix of generation and energy storage devices at various scales, demand-side flexibility, and transmission and distribution network assets holds the potential to reduce overall electricity costs relative to a system with uncoordinated investments (Baldick & Kahn, 1993; Ignacio J. Perez-Arriaga et al., 2016). In power systems where actors remain vertically integrated across generation, transmission, distribution, and retail, this coordination requires a set of internal planning and operating decisions and appropriate external price signals, incentives and/or communications with electricity users. In systems with competition in generation and/or retail, this coordination requires multilateral arrangements between monopoly network providers and market actors and, in many cases, market-facilitated price signals and contracts for energy, capacity, and ancillary services. Wholesale market constructs and the planning processes orchestrated (in part) by bulk system balancing authorities (BAs) (2) provide the frameworks for coordinating investment planning and operation at the bulk system level, but similar arrangements are nascent or non-existent at the distribution level.

    Sections 2 and 3 provide a literature review and background on the interplay between industrial structure and coordination of actors. Section 4 begins with a discussion of which actor--the distribution system operator or the bulk system balancing authority--will be responsible for price formation at the distribution level. Section 4 discusses necessary improvements in short term price signals, and Section 5 discusses the role of long-term contracts and forward markets for distribution level services.

    This paper has implications for two questions that are currently being debated by regulators and policy makers globally:

  2. What is the role of the distribution system operator (DSO)--independent or otherwise--in future power system operations?

  3. What market mechanisms, if any, might be needed under different institutional arrangements to coordinate efficient investment and operational decisions across various actors?

    We argue that price signals at the distribution level must be dramatically improved to ensure that network users adopt and operate DERs in a way that maximizes the welfare of the power system as a whole, rather than for any one network user at the expense of others. We argue that no single actor today has visibility into the distribution system and capability to run the systems necessary for efficient price formation. We describe three possible paths forward, and describe the key tradeoffs between these paths. Improving price signals at the distribution level will also require significant improvements in electricity tariff design. Default tariffs must align individual incentives with cost-savings opportunities for the system as a whole. In markets with retail competition, settlement rules for retailers must be updated to ensure that these retailers are financially responsible for the customers they serve and economically incentivized to facilitate efficient consumption, injection, and investment decisions. Finally, new market mechanisms such as auctions for non-wires alternatives may be necessary, as short run prices may not coordinate the efficient level and timing of investment in non-wires alternatives.


    Recent literature on coordination at the distribution level has concentrated on three broad issues:

    1) the evolving roles of the DSO in system operations;

    2) coordination of the DSO and bulk system balancing authorities (BAs) and power markets;

    3) the role of price signals in incentivizing efficient DER investment and operations.

    We briefly summarize the literature on each of these three dimensions below.

    The evolving roles of the DSO in system operations. The U.S. Department of Energy's DSPx Initiative (2017) defines many of the capabilities and functions of future distribution network, system, and market operators in a descriptive fashion, focusing on the actions required to ensure reliable system operations. Martini et al. (2015) and Kristov et al. (2016) discuss alternative models for assigning distribution level roles to power system actors and advocate for increasing the responsibility of the DSO in power system balancing and real time operations. Similarly, Corneli et al. (2015) offers two descriptive high-level visions of the future of DER integration for distribution utilities, but does not compare the potential efficiency of these visions or the key economic tradeoffs. Bahramirad et al. (2016) describes a vision for a DSO that takes primary responsibility over scheduling resources and demand within its service territory, but do not compare this structure to other potential structures.

    DSO-BA coordination. A number of authors have focused on coordinating DSO activities with bulk system balancing authorities. Ruester et al. (2014) highlight the changing nature of the DSO vis-a-vis the bulk system BAs and argue for increased regulatory oversight to ensure that DSOs do not abuse their monopoly positions in aggregation and DER markets. Both Martini et al. (2015) and Kristov et al. (2015) largely dismiss the potential for a "total TSO" model, in which the bulk power system balancing authority manages most distribution level operations. California Independent System Operator (CAISO) et al. (2017) provides a near term roadmap for coordination in the California context, focusing on ensuring that distribution network constraints are respected in market and balancing operations. Many other industry reports and academic papers have focused on this issue, primarily outlining different methods for ensuring operational feasibility in the near term (see, for example, (ENTSO-E, 2017)).

    The role of price signals. Scholars have analyzed the interaction between price signals and DER adoption for well over a decade. For example, Firestone et al. (2006) highlight the negative impact of fixed-charges in tariffs on fossil-fuel-based DG. In more recent years, a litany of studies have focused on network cost recovery in the face of distributed solar (Borenstein, 2017; Brown & Sappington, 2017; Darghouth, Barbose, & Wiser, 2011), the impact of demand charges on storage economics (Hledik & Greenstein, 2016; Neubauer& Simpson, 2015), and incentivizing the optimal placement of DERs through tariffs (Ignacio J. Perez-Arriaga et al., 2016; Sioshansi, 2016). Related to the discussion of DER economics and pricing, interest in distribution-level Iocational marginal prices (DLMPs) has accelerated in recent years. The literature on DLMPs is vast, but researchers are broadly focusing on methods for creating efficient short run marginal costs accounting for distribution level constraints (M. Caramanis, Ntakou, Hogan, Chakrabortty, & Schoene, 2016; Papavasiliou, 2017).

    We build upon the body of literature by bringing the tariff design debate into the discussion of coordination mechanisms needed for vertically and horizontally disaggregated industries. We also analyze the role of the DSO in system operations in a transaction cost economics lens, providing a new perspective with which to analyze the issue. By translating the foundational theory and modern work in markets and hierarchies to the present situation, this provides a more holistic framework with which to make informed structure decisions.


    The power sector was historically dominated by either a regional, vertically integrated monopoly generator or a relatively limited number of power producers investing in large plants. Entry into the generation sector in this paradigm was...

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