Consumer Savings, Price, and Emissions Impacts of Increasing Demand Response in the Midcontinent Electricity Market.

AuthorDahlke, Steve

    A significant challenge associated with the development of wholesale electricity markets is the lack of demand-side participation. In most electricity markets, consumers face static prices that often do not change over the course of days, weeks, and months, while the costs to supply electricity change significantly across these time scales. The result is a mismatch between real-time market conditions and retail prices that causes over-consumption during high-price periods and under-consumption during low-price periods (Schweppe, Caramanis, Tabors, and Bohn, 1988; Faruqui and George, 2002). This inefficiency increases spot price volatility, makes it more difficult for operators to manage physical constraints, and increases vulnerability to the exercise of market power (Bushnell, Hobbs and Wolak, 2009). In the MISO region there is a significant potential for electricity demand response that is largely unmet (Faruqui, Hajos, Hledik, and Newell, 2009). Barriers in the region include state regulatory hesitancy and wholesale market rules designed for large centralized power generation (Cappers, MacDonald, Goldman, and Ma, 2013). These regulatory barriers keep economic demand response resources out of the wholesale energy market, creating an inefficiency that leads to artificially high prices.

    This paper quantifies wholesale consumer savings and other impacts of increasing economic demand response (DR) dispatch in the MISO energy market using a bottom-up (1) hourly supply and demand model for the Midcontinent Independent System Operator wholesale electricity market (also referred to as Midcontinent ISO, or MISO; in the remainder of the paper we will use the acronym MISO). The MISO market spans 15 U.S. states and facilitates trade across 65,000 miles of electric transmission and between 200 gigawatts of electricity generation. We model DR dispatch across three different MISO subregions, North, Central, and South, defined in Figure 1 (MISO, 2014).

    We use historic data to simulate market effects from dispatching a range of existing DR resources that are currently out of the market. All datasets and code for this analysis, as well as online appendices, are publicly available on the Open Science Framework repository at Our study is not the first to show energy market benefits from increased DR (e.g. see Famqui, Hledik, Newell, and Pfeifenberger, 2007; Walawalkar, Blumsack, Apt, and Fernands, 2007; Braithwait and Eakin, 2002; Aalami, Moghaddam, and Yousefi, 2009). However, as discussed in Cappers et al. (2013), DR in the MISO market is shaped by a unique set of state-jurisdictional regulatory and market rule challenges that do not exist in other competitive wholesale markets, warranting a region-specific study. We make several contributions to the literature. First, we estimate market effects from increased DR dispatch for the MISO market, the largest power system in the United States by geographic scope and one of the largest electricity markets in the world. Second, we fill a gap in the energy literature characterized by a lack of studies on incentive-based DR. Third, we apply microeconomic theory to model the costs and benefits of dispatching incentive-based DR in a wholesale electricity market using a net-benefits criteria, described in section 2.2. Finally, we combine DR data from the U.S. Energy Information Administration (EIA) with ISO market data in a dynamic supply and demand simulation model. Other novel characteristics of this study include estimating wholesale DR market offers from EIA data, calculating the sensitivity of results to a range of DR energy shifting assumptions, and producing estimates of carbon emissions impacts for various DR deployment scenarios.

    The rest of this paper is organized as follows. In section 2 we define and classify DR for the purposes of our analysis, and motivate our research design and modeling strategy. In section 3 we describe the methodology and data used for the analysis. In section 4 we present our results, and in section 5 we conclude with a summary of results and subsequent policy recommendations. Our modeling shows how increasing cost-effective DR dispatch can generate consumer savings net of system costs by lowering prices under typical peak operating conditions. We also show how the market impacts of DR increase exponentially when deployed during critical peak operating conditions.


    2.1 Background

    Demand response in electricity markets encompasses a range of market participant activities; programs, and technologies. DR can be classified into two broad categories, according to definitions adopted by the U.S. Department of Energy, the Federal Energy Regulatory Commission (FERC), and numerous academic articles (U.S. DOE, 2006; U.S. FERC, 2009; Albadi and El-Saadany, 2008). The first category of DR is defined as "changes in electricity usage by end-use customers from their normal consumption patterns in response to changes in price." These types of demand response resources are referred to as price-based programs, and encompass electricity price structures designed to change over time including time-of-use (TOU), critical-peak-pricing (CPP), and real-time-pricing (RTP) programs. The second category is defined as "incentive payments designed to induce lower electricity use at times of high wholesale market prices or when system reliability is in jeopardy." These resources are referred to as incentive-based programs and include direct load control (DLC) and interruptible/curtailable (I/C) load programs.

    The MISO region of the United States historically has had a higher proportion of DR relative to total load compared to other regions in the United States for several important reasons. First, some states in the region require utilities to invest a percentage or two of revenue from retail sales in DR programs. Second, utilities in the region have historically had favorable resource adequacy rules that allow load management to be counted towards meeting reserve requirements, generating savings or revenues from the DR even if it is never deployed. Third, the customer base in this region has a significant fraction of industrial load that is amenable to interruption (Cappers, Goldman, and Kathan, 2009). EIA reports that utilities in MISO have 4.4 GW of DR (U.S. Energy Information Administration, 2016), while MISO reports they have 5.7 GW of DR resources available (MISO Planning Resource Auction, 2016). This discrepancy is largely due to the fact that EIA's DR survey form covers electric retail utilities, and not large end-use customers that register their DR program directly with MISO.

    Despite a large portion of DR in the MISO region, the resources are deployed at a much lower frequency than the rest of the country. For example, in 2015 only 22% of the available DR resources in the MISO market were deployed, compared to 42% in the rest of the country (U.S. EIA, 2016). In California, a particularly active market for DR, 64% of available resources were deployed. During the few occasions when DR resources in the MISO are deployed, they are often done so by individual utilities outside of the MISO market, and show up to the market operator as unexpected load reductions. However, the large majority of DR is available for direct deployment by MISO up to at least 5 times per summer through a product category called a "Load Modifying Resource" (LMR). LMRs do not directly participate in the energy market and are only called on during grid emergencies. However, many LMR resources are "economic" during peak periods in that they have a lower marginal cost of dispatch than the generators in the energy market that get dispatched ahead of them. MISO has an energy DR program available but participation is negligible due to market rule and regulatory barriers.

    MISO has historically underutilized the DR assets available to it. Since the launch of MISO's energy markets in 2005, MISO has only deployed its registered DR under the LMR asset classification twice at the time of writing. On April 4th, 2017 during a maximum generation event triggered by unseasonably high temperatures, MISO called on just over 700 MWs of LMRs in the southern portion of its footprint (MISO LMR Performance, 2017). The only other deployment in MISO's history we have record of was in 2006 (Potomac Economics, 2017).

    Various market and state regulatory barriers prevent better DR participation in the MISO market. MISO's rules for economic Demand Response Resources require a minimum size threshold of at least 1 megawatt (MW) to participate in the market (2) (MISO Tariff, 2017; MISO BPM, 2016). Additionally, MISO's rules make it difficult to aggregate small DR resources to meet the minimum size threshold. (1) This prevents many demand response resources from entering the market. Other markets that have more active DR participation, including PJM and ISO New England, have corresponding minimum size thresholds of 0.1 MW and do allow aggregation of resources across pricing nodes. The second reason for low DR participation in MISO is state regulatory resistance to giving up control of regulated DR assets in the competitive market. As a result, regulators often will not let utilities enter their DR assets into the wholesale markets, and most states in the MISO region have banned commercial activity by third party DR aggregators (Cappers et al. 2013). More information on regulatory and technical reasons why demand-side management programs have underdelivered in wholesale electricity markets around the world are provided by Wirl (2000) and Rivers and Jaccard (2011).

    2.2 Modeling DR in wholesale markets

    In this section we develop a general microeconomic model that is applied to understand the effects of deploying incentive-based DR in a wholesale electricity market under a net-benefits criterion. First, it is important to clarify that consumers in the wholesale market are...

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