As variable, distributed generation increasingly becomes a prevalent source of generation in regions, changes in capacity market dynamics will have a profound impact on generating assets and their future economic viability.

Distributed Generations Future Impact on the U.S. Capacity Markets

Samir Succar | ICF International

Executive Summary

The impact of Distributed Generation on market operations and system reliability becomes increasingly dire as penetration levels increase in those regions where capacity market mechanisms provide the primary vehicle maintaining resource adequacy. The variability of the resource and its location on the low-voltage grid undermine efficient market operation at high penetrations by effectively decoupling price formation from supply/demand fundamentals. While regions such as California at the forefront of variable resource integration can provide useful lessons, the provision of flexibility by way of state procurement mandates is untenable in the context of organized markets that rely on capacity market constructs for resource procurement. Although such solutions might work well in other regions, they would only further compromise the integrity of price formation in markets such as PJM and New England. Indeed, if one central aim of the organized markets is to shift the risk of efficient investments to investors and away from consumers, the integrity of the capacity market construct must remain a necessary prerequisite for the future design of the system.

Growth from the Bottom Up

The future of the utility industry has become a central focus for many as the sector grapples with several existential threats. Among the chief threats looming on the horizon is the large projected growth in distributed energy resources (DERs) and its potential to compound the impacts of the anemic growth in net load observed in many regions today. But this growth in DERs is relatively recent. While the resource base has certainly grown significantly for specific resources in particular regions such as the solar photovoltaic (PV) generation in California or the demand response in PJM, on a national basis these resources still occupy a relatively small fraction of the overall mix. Nevertheless, the conditions for growth for this class of resource are approaching a tipping point toward widespread viability in many more markets and there is growing enthusiasm around the potential for growth of DERs in the years and decades to come. Note, for example, the tremendous growth rate for solar in particular in the forecast presented in Figure 1 below.

Figure 1. ICF’s Forecast of DER Penetration

The growth of distributed generation and its impact on price formation in U.S. capacity markets implies a fundamental shift in the structure of resource adequacy mechanisms. As variable, distributed generation increasingly becomes a prevalent source of generation in regions, changes in capacity market dynamics will have a profound impact on generating assets and their future economic viability. Without commensurate changes in capacity market structure to account for these changes, system reliability will be compromised.

Despite a great deal of discussion around DER trends and their prospects for growth, the impact of these resources on generation assets and price formation in the market has been largely overlooked. The impacts of these resources on system operation and load growth have received a great deal of attention through the volumes of integration and impact studies in the literature. But while the impact on the diurnal load profile and the continuing uproar surrounding net metering policies have received extensive media interest, the sometimes subtle discussion of the impact of these resources on market structure and on the future viability of generating assets more broadly has not received the attention it deserves. Because of the geographic distribution of distributed PV resources, their place in the power system topology, and the variable nature of their output, the traditional market constructs built around fixed-load and dispatchable power begin to break down in fundamental ways. While some might characterize this as the triumph of new technologies over the power plants of the past, the truth is much more complex and the stakes for addressing these changes to the market are much higher than such a simple narrative suggests. In fact, the ability of the markets to ensure reliable power delivery rests on the efficient operation of these market, and so the need to find solutions to these issues is far more important than the relative economics of any given fuel source or technology .

These market impacts will be felt most acutely in organized markets with well-developed capacity market mechanisms. In those regions, the adequacy of system resources for meeting the demand for electricity depends on effective mechanisms for price formation to provide market signals to incent investment in new resources when conditions of supply and demand warrant it. These mechanisms are critical to both the integrity of the market and to the maintenance of resource adequacy. To understand the impact of distributed energy resources on price formation, it is important to understand not only the scale of these resources but their output characteristics and their place in the power system topology.

Variable and Distributed

Sources of generation like wind and solar with a free fuel source will operate at zero marginal cost (maintenance and operation costs are effectively zero). This leads to the canonical price suppression effect wherein zero-fuel-cost plants flatten the left side of the supply curve, resulting in lower wholesale energy prices in the real-time market. As observed in the Texas context, real-time prices can descend into negative territory when a production-based incentive drives the effective short-run marginal cost below zero and there is insufficient transmission capacity to move power to load pockets. These impacts alone have the impact of distorting capacity prices without mitigating measures and, in fact, we have seen that the reduction of infra-marginal revenues in Europe have led to the recent shut down or mothballing of 30 GW of gas fired capacity, including last year’s decision by E.On SE to mothball a two-year old combined cycle unit in Malženice, Slovakia. 

Unlike utility scale systems that can rely on the bulk power grid to more effectively leverage geographic diversity of the resource, DG resources interconnect at the distribution level where the impacts of variability are not as easily mitigated. The aforementioned negative prices in Texas were effectively alleviated in large part through large-scale transmission expansion and the development of the competitive renewable energy zone (CREZ) transmission lines. In contrast to this, DERs exist at the low-voltage side of the power system and therefore do not have the same level of access to the bulk grid and its ability to transfer power across great distances. Distribution feeders function as the capillaries of the power system, and with the uneven geographic distribution of DERs leading to heavy concentration of systems on individual feeders, the ability to leverage geographic diversity of the resource across weather fronts and climatic zones becomes a much greater challenge. This further exacerbates the price suppression phenomenon described above and creates the need for other balancing measures and quickly responding resources.

The critical question from a market integrity standpoint is how do the price suppression impacts and the variability of distributed resources impact price formation in the markets in general and in the capacity markets in particular? For those markets such as New England and PJM that rely on three-year capacity market constructs to maintain resource adequacy, market fundamentals rely on the assumptions of an accurate valuation of resource contribution to loss of load expectation and an accurate reflection of supply and demand dynamics.

The Impact of Distributed PV on PJM Capacity Prices

The PJM market operates one of the most well-developed capacity market constructs in the U.S. and provides a unique window into how DERs could substantially call into question both the assumptions of accurate resource valuation and price signals accurately reflecting the market’s supply/demand balance. PJM’s reliability pricing model (RPM)—its three-year capacity market—relies on the mechanism of net cost of new entry (CONE) to form the upper boundary of the market demand curve, the so-called variable resource requirement curve, that dictates the clearing price in the base residual auction (BRA). Because net CONE is defined as the cost of adding a new resource minus the expected energy revenue from that generator, the impact of cost suppression will be to inflate net CONE. In fact, the ability of distributed generators to underbid all conventional generation in economic dispatch on the basis of near-zero, short-run marginal cost means that expected capacity factors for all plants will be lower in those regions where DER penetrations are high. The subsequent impact on bidding behavior across the market would be to inflate capacity prices to unsustainable levels.

The recently released PJM renewable integration study (PRIS) looked at ten scenarios for the market through 2026 at varying levels of wind and solar deployment with levels of distributed solar energy resources exceeding 30 GW through 2026 in the PJM footprint. That level of deployment represents roughly 18% of the peak demand in the PJM footprint in that year. In places like New Jersey and Maryland with favorable policies and rate environments for PV and where the market for PV has outpaced the rest of the PJM region, one could expect substantially higher capacity penetrations locally under such scenarios. Furthermore, the saturation in specific LMP zones and specific feeders could even exceed total peak load several times over to the extent that solutions are in place to accommodate high volume bidirectional power flow at the distribution level. This means that without proper planning, price supports and other incentives could drive local penetration levels to unprecedented levels.

Under these types of conditions, it is not unreasonable to expect significant impacts on energy prices in the real time market with significant commensurate impacts on the clearing price in RPM. This impact is especially high for distributed resources, because, unlike utility scale resources that can bid into the capacity market on the basis of their impact on loss of load expectation (i.e., their effective load carrying capability or ELCC), distributed resources do not participate in capacity procurement for the regional transmission organization. Therefore, while systems interconnecting to the bulk system can bid in an amount of unforced capacity equal to the determined capacity value (central PV for example was found to have an ELCC of 62%–66%), the distributed resources cannot bid their capacity in the BRA which means that they are effectively inflating the demand curve through price suppression without offsetting that by extending the capacity supply curve.

While price distortions such as these are counterproductive for effective market operation, there might be a tendency to view high-capacity prices as a positive price signal incenting new entry into the market, especially in the current capacity-long environment and in light of the most recent BRA for the 2016–2017 delivery year, which saw prices collapsing in specific regions. This instinct should be tempered for two reasons: (1) price formation that diverges from fundamental supply/demand balance will produce inefficient allocation of capital in the marketplace, and (2) this trend is also coupled with an inability of the current capacity market constructs to fully capture the value of all resource attributes, which means that high capacity prices could produce not only the wrong amount of capacity but the wrong type of resources as well.

Resource valuation and flexibility concerns are central to price formation in the market. It is clear that in addition to the capacity market distortions already present due to the price suppression, if the need for flexibility and fast ramping resources is not somehow internalized into the capacity procurement mechanism, then the resource adequacy objective function is fundamentally incomplete. That means that in addition to inefficient capital allocation and resource mismatch, the system operator’s view of resource adequacy is fundamentally incomplete because the traditional assumptions around dispatch and the relationship between nameplate capacity and loss of load expectation are undermined as the participation of variable energy resources, and distributed generation in particular, continues to increase.

What the East Can Learn from California…and What It Can’t

California has been at the forefront of this issue in many respects. The state accounts for roughly half of the residential and commercial PV in the U.S. and has more than twice as much capacity than any other state. Furthermore, the sustained deployment rates necessary to meet California’s 33% renewable portfolio standard by 2020 are projected to impose significant new flexibility requirements on the system.

The impact on generating assets in the state have been that relatively new plants such as the Sutter Combined Cycle have threatened retirement due to insufficient revenue in the market. In the discussion of Calpine’s petition stemming from that case, Commissioner Mark Ferron of the California Public Utility Commission (CPUC) noted, “…it appears we may have a ‘hole’ in our market and planning structure whereby there are insufficient economic incentives for generating plants which provide useful flexible attributes to cover the cost of maintaining these plant[s] in operation.” In order to address the flexibility needs of the market, the California Independent System Operator (CAISO) proposed a flexible capacity and local reliability resource retention, or FLRR, mechanism to procure flexible capacity as a way to ensure uneconomic but needed generation units remain operational for reliability purposes. While this proposal was ultimately rejected by FERC in March 2013, the CPUC in June agreed to require utilities and other load-serving entities to meet flexible capacity procurement targets set by the Commission starting in 2014. The CPUC has also proposed a Reliability Services Auction to provide a voluntary platform for capacity procurement and in September 2013 approved a 1.3 GW energy storage mandate designed to bring new energy storage technologies to market and improve system flexibility.

The penetration of renewable generation in California is already above 20% whereas in PJM the share of generation from renewable energy is still much lower. The contribution from wind is still less than 2% and solar is only a small fraction of that level. Therefore, the California experience could potentially provide some useful lessons if the penetrations of variable resources in PJM were to increase substantially. However, where California will not be a useful template is in the area of capacity procurement and price formation. The experience with organized markets has been very different in various regions of the country and while markets such as PJM have embraced capacity market mechanisms for maintaining resource adequacy, this has not been the path chosen in California. This means that the challenges in those regions that have opted for the implementation of a capacity market mechanism must continue to ensure that product definitions, including performance obligations or performance incentives such as those required under FERC Order 755, are well designed and matched to the system needs, given the resource mix on the system. It also means that they must continue to effectively screen out subsidized resources from receiving capacity payments to ensure the integrity of the market. While resource mandates such as the CPUC storage standard could work well in areas where capacity procurement relies heavily on bilateral agreements and the like, in markets such as PJM such a mechanism to deploy a specific flexibility solution would undermine the price formation of the market and the ability of the rest of the resource base the remain financial viable. If one central aim of the organized markets is to shift the risk of efficient investments to investors and away from consumers, the integrity of the capacity market construct must remain a necessary prerequisite for the future design of the system.


The variability and location of distributed generation resources mean that their growing participation in organized markets undercuts many of the assumptions around a dispatchable resource base and fundamentally alters the definition and scope of what must be considered in the context of resource adequacy. The California experience offers a view as to the challenges likely to be faced by existing generators as DER penetrations increase in PJM and ISO-NE, but the lessons learned will not be directly applicable and the solutions will need to be unique. There remain significant challenges in these markets to address the market integrity and resource adequacy challenge that these resources pose to the system. Whether policies and market conditions favor distributed resource to the extent that they reach significant penetrations is still largely uncertain, but the improved economics of these technologies suggest that in select areas participation is poised to accelerate rapidly. As it does, market design must adapt to accommodate this swiftly changing landscape to ensure that sufficient resources come online and that the market efficiently allocates capital to bring online those resources equipped to address the full scope of future system needs.

©2014 ICF International, Inc.

Any views or opinions expressed in this paper are solely those of the author(s) and do not necessarily represent those of ICF International. This White Paper is provided for informational purposes only and the contents are subject to change without notice. No contractual obligations are formed directly or indirectly by this document. ICF MAKES NO WARRANTIES, EXPRESS, IMPLIED, OR STATUTORY, AS TO THE INFORMATION IN THIS DOCUMENT.

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About the Authors

Samir Succar joined ICF International in 2012 and currently serves as Technical Specialist in the Energy Advisory and Solutions team. Dr. Succar analyzes and models power market supply-demand fundamentals, develops power market price forecasts, and performs generation asset valuations. Prior to joining ICF, he was a staff scientist at the Natural Resources Defense Council. Before that, he was a member of the research staff of the Energy Systems Analysis group at the Princeton Environmental Institute (PEI) of Princeton University where his research focused on integration issues associated with utility scale renewable energy and on enabling technologies for intermittent generation. A key focus of this work is the implementation of energy storage as a strategy for enhancing transmission infrastructure utilization and mitigating the intermittency of renewable energy with particular attention to compressed air energy storage (CAES) and other bulk storage technologies. Previously, Dr. Succar worked at the Princeton Macroelectronics Group developing fabrication methods for solution processed organic thin film transistors (OTFTs) and at Schlumberger ATE developing charged particle optics for voltage contrast defect detection systems. He holds a BA in Physics from Oberlin College and an MSE and PhD in Electrical Engineering from Princeton University.

The content & opinions in this article are the author’s and do not necessarily represent the views of AltEnergyMag

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