Paul Sotkiewicz

Efficient market-clearing prices in markets with nonconvexities

This paper addresses the existence of market clearing prices and the economic interpretation of strong duality for integer programs in the economic analysis of markets with nonconvexities (indivisibilities). Electric power markets in which nonconvexities arise from the operating characteristics of generators motivate our analysis; however, the results presented here are general and can be applied to other markets in which nonconvexities are important. We show that the optimal solution to a linear program that solves the mixed integer program has dual variables that: (1) have the traditional economic interpretation as prices; (2) explicitly price integral activities; and (3) clear the market in the presence of nonconvexities. We then show how this methodology can be used to interpret the solutions to nonconvex problems such as the problem discussed by Scarf [Journal of Economic Perspectives 8(4) (1994) 111].

Nodal pricing for distribution networks: efficient pricing for efficiency enhancing DG

As distributed generation (DG) becomes more widely deployed, distribution networks become more active and take on many of the same characteristics as transmission. We propose the use of nodal pricing that is often used in the pricing of short-term operations in transmission. As an economically efficient mechanism, nodal pricing would properly reward DG for reducing line losses through increased revenues at nodal prices and signal prospective DG where it ought to connect with the distribution network. Applying nodal pricing to a model distribution network, we show significant price differences between buses reflecting high marginal losses. Moreover, we show the contribution of a DG resource located at the end of the network to significant reductions in losses and line loading. We also show the DG resource has significantly greater revenue under nodal pricing, reflecting its contribution to reduced line losses and loading.

The Wind at Our Backs

This article examines the design and operation of a cross section of electricity markets in the United States. Experience with the evolution of such markets in the recent past to accommodate limited amounts of variable renewable energy is discussed. Based on this experience, insights into what is necessary for these markets to be able to accommodate significantly higher levels of variable renewable energy generation in the future are provided.

Impact of variable renewable energy on US electricity markets

This paper reviews the design and operation of a number of large, regional organized markets in the US, as well as the operation of stand-alone single balancing area bilateral markets, from the viewpoint of integrating large amounts of variable output renewable energy sources. Significant differences between the two types of markets are noted. In addition, a series of shortcomings of the first generation market designs are discussed, and some thoughts on the design changes required to enable greater participation of variable output generators in the market are provided.

The Evolution of the Market: Designing a Market for High Levels of Variable Generation

Renewable energy was not the initial justification for electricity markets, but it is rapidly becoming a driver for new markets and market design changes. Starting in 1982 with market reforms in Chile, competition has been introduced into wholesale electricity markets around the world. This trend is likely to accelerate with countries such as China planning a major restructuring of power systems that could result in electricity markets.

Regulatory Evolution, Market Design and Unit Commitment

In the context of competitive wholesale electricity markets, the unit commitment problem has shifted from a firm level optimization problem to a market level problem. Some centralized market designs use it to ensure reliability and determine day-ahead market prices. This chapter reviews the recent history of short-term electricity markets in the United States to evaluate the experience with alternative market designs and the implications for unit commitment modeling. It presents principles for the design of the next generation of unit commitment-based markets.

Value of conventional fossil generation in PJM considering renewable portfolio standards: A look into the future

Widespread, large-scale deployment of renewable generation resources with low or zero running costs can have the effect of reducing average locational marginal prices (LMP) in PJMs Energy Market. A PJM study from 2009 showed the introduction of 15 GW of wind resources in PJM would reduce average LMPs by

The value of intermittent wind DG under Nodal Prices and Amp-mile Tariffs

5/MWh. Lower LMPs in the PJM Energy Market will have the effect of reducing net energy market revenues that can be earned by conventional fossil generation resources and place such resources at a greater risk for retirement unless sufficient revenue can be earned elsewhere in PJMs markets. If conventional fossil resources can earn sufficient revenues in PJMs Reliability Pricing Model (RPM) Capacity Market that make up for reduced net energy market revenues, then conventional fossil generation can and will remain a large part of the generation resource mix. However, conventional fossil generation would, through higher RPM Capacity Market prices, provide greater value as Capacity Resources than as energy resources in the presence of widespread penetration of renewable generation resources. Such a transition makes sense as renewable generation resources are intermittent in their output and are given a considerable discount off their nameplate capacity values as Capacity Resources due to their intermittency. Yet, given renewable portfolio standard (RPS) and production tax credit policies, renewable resources have greater value based on their energy output, value beyond net energy revenues that can be earned in PJMs Energy market, than as a Capacity Resources. The current economic and policy environment provides a preview of the evolving value of conventional fossil generation from energy towards capacity. As a recent PJM study has shown, coal-fired generation in PJM has seen a dramatic decline in net energy market revenues as the recession and declining natural gas prices have reduced the value of energy from these resources. Additionally, these coal-fired resources are facing large capital investments in environmental retrofits that must be paid from earnings in PJMs Markets. Given the erosion of net energy market revenues, additional revenues would need to be earned in the RPM Capacity Market in order to remain financially viable and avoid retirement. In order to remain financially viable these resources would need to earn additional revenues from PJMs RPM Capacity to continue operating into the future.

Smarter Demand Response in RTO Markets: The Evolution Toward Price Responsive Demand in PJM

In this paper we apply the recently proposed Nodal Pricing and Amp-Mile tariffs for distribution networks to the case where a wind distributed generator is located in the network. The ability of this tariff structure to capture the real cost and benefits of DG is analyzed for this case of intermittent generation using real wind and network data from Uruguay and a standard wind turbine. A comparison is made in relation to the case with no DG placed in the network, to the case with controllable DG and to the case of intermittent DG of different capacity factors. We find that in expectation intermittent wind DG does little to reduce overall line losses or reduce peak line utilization. Consequently, under Nodal Pricing and Amp-Mile tariffs the intermittent wind resource collects very little additional revenue over the case where the intermittent wind DG source is simply paid the price of power exclusive of losses and is not compensated for freeing up network capacity.

The Fully Integrated Grid: Wholesale and Retail, Transmission and Distribution

PJM, the largest organized U.S. electricity market, offers a new option for market participation by load reduction capability, price responsive demand (PRD). Price responsive demand is the culmination of decades of work in demand response and of several years of work in wholesale market design and retail dynamic rates. Customers empowered by timely and detailed usage information will be able to make decisions about when and how to use electricity in response to market prices and automated controls will implement their decisions. PRD has been enabled by the rapid emergence of smart grid technology, deployments of advanced metering infrastructure (AMI), the implementation of dynamic retail rates, and the continued growth of demand response (DR) resources in PJM. This chapter lays out how PRD will integrate the wholesale and retail electricity markets and describes how PRD will enhance energy and capacity market price formation, improve reliability and operational control, and increase market efficiency while reducing transaction costs.