https://doi.org/10.1016/j.eneco.2024.107790

Working Paper

Podcast Episode

Abstract
This paper investigates the design and analysis of price formation in wholesale electricity markets given variability, uncertainty, non-convexity, and intertemporal operating constraints. The paper’s primary goal is to develop a framework to assess the many resource participation models, reserve product definitions, and enhanced pricing methods that have arisen in U.S. systems, especially in the context of growing contributions from wind, solar, and storage. Departing from the static models typically used for electricity auctions based on thermal resources, the paper situates price formation within the sequential decision problem faced by system operators. This more complete description of the problem has several implications for price formation. Since prices are derived from operational models, algorithmic choices in the design of policies for the sequential decision problem influence the prices ultimately formed. In numerical tests, policy variants with comparable operational performance (within 4% in terms of total cost) lead to substantial differences in prices and resource remuneration. Storage is particularly affected, earning revenues ranging from 57% to 117% of the amount suggested as economically efficient by a benchmark approximated through stochastic programming.

https://www.oxfordenergy.org/wpcms/wp-content/uploads/2024/04/OEF-140-Powering-the-Future.pdf

https://doi.org/10.5547/01956574.45.1.sris

Working Paper

Abstract
Financial instruments that help provide revenue certainty are fundamental for project finance in liberalized electricity markets. Improved management of locational risk caused by network congestion is becoming increasingly important with a growing share of production from geographically remote renewable resources. Nodal markets have financial transmission rights (FTRs) to enable participants to manage locational risk, but there is no evidence that FTRs have been used to support project finance. Through a stochastic equilibrium model in which market participants invest in production assets and trade risk, we show that long-term FTRs promote surplus-maximizing generation investments and reduce the cost of capital. Investors pair them with energy price hedges and thus protect themselves against both types of risk. Our results suggest that altering the definition and allocation of FTRs to match the needs of project finance, e.g., by enabling new generators to procure a long-term right at the time of interconnection, could help ensure a complete risk market and encourage efficient investments.

https://doi.org/10.1109/TEMPR.2023.3322531

Full Text

Abstract
This paper considers the evolution of electricity market design as systems shift toward carbon-free technologies. Growth in wind and solar generation is likely to lead to increased price volatility on diurnal and seasonal timescales. In the standard risk-neutral optimization framework, volatility does not pose any theoretical issues for market design. Because revenue volatility has the potential to lead to a higher cost of capital for investments in competitive markets, however, many observers have questioned the viability of competitive models for resource adequacy as wind and solar grow in importance. To assess the role of risk management in overall market performance, we construct a stochastic equilibrium model incorporating financial entities as hedge providers for investors in generation capacity. Unlike in the standard optimization framework, the cost of capital in the equilibrium framework is endogenously determined by interannual revenue volatility and the risk measures used by market participants. Surprisingly, exploratory numerical tests suggest that overall investment risk may be lower in systems dominated by variable renewables due to reduced exposure to fuel price uncertainty. However, changes in investment risk are not uniform across resource types, and increased risk for peaking and backup resources contributes to lower reliability in the modeled future systems.

https://doi.org/10.1109/TEMPR.2023.3315953

Full Text

Abstract
Part 1 of this two-part paper describes the impact that uncertainty has on the design and analysis of price formation policies in the non-convex auctions conducted by U.S. wholesale electricity market operators. Using first a toy model and then a large-scale test system, Part 2 demonstrates the difference in prices under the idealized benchmark of ex ante convex hull pricing defined in Part 1 versus existing methods, in particular documenting the potential for suppression of volatility and therefore under-compensation of flexibility by existing methods. The examples highlight that inefficient spot price formation can induce inefficient forward commitments of generators, necessitating out-of-market intervention to restore a reliable and efficient operating plan. Given the potential side effects of existing policies for investment and operation, we suggest two elements in a reoriented approach to the price formation problem: first ensuring that prices exhibit full-strength volatility, and second ensuring that risk-averse market participants have sufficient ability to manage this volatility.

https://doi.org/10.1109/TEMPR.2023.3315956

Full Text

Abstract
Operators of organized wholesale electricity markets attempt to form prices in such a way that the private incentives of market participants are consistent with a socially optimal commitment and dispatch schedule. In the U.S. context, several competing price formation schemes have been proposed to address the non-convex production cost functions characteristic of most generation technologies. This paper considers how the design and analysis of price formation policies for non-convex markets are affected by the uncertainty inherent in electricity demand and supply. We argue that by excluding uncertainty, the analytical framework underlying existing policies mischaracterizes the incentives of market participants, leading to inefficient price formation and poor incentives for flexibility. We establish favorable theoretical properties of a new construct, ex ante convex hull pricing , and demonstrate the difference between this idealized benchmark and existing methods on a large-scale test system. Given increased operational uncertainty with a transition to wind and solar generation, distortions caused by poor incentives for flexibility are likely to grow without improved price formation in organized wholesale markets.

https://doi.org/10.1016/j.eneco.2023.106943

Working Paper

Abstract
Liberalized electricity markets often include resource adequacy mechanisms that require consumers to contract with generation resources well in advance of real-time operations. While administratively defined mechanisms have most commonly taken the form of a capacity obligation, efficient markets would feature a broad array of arrangements adapted to the risk profiles and appetites of market participants. This article considers how the financial hedge embedded in alternative resource adequacy contract designs can induce different responses from risk-averse investors, with consequences for the resource mix and market structure. We construct a stochastic equilibrium model describing a competitive market with incomplete risk trading and compute investment equilibria under different contracting regimes. Two policy recommendations result. First, to avoid creating inefficiency by crowding out other forms of risk sharing, system operators should allow resources contracted through other means to opt out of mandatory capacity mechanisms, with their contribution to those requirements subtracted from administratively defined demand curves. Second, if they wish to promote a single contractual form, regulators should consider replacing existing option-like capacity mechanisms with a shaped forward contract for energy. Beyond these recommendations, we discuss the tension that liberalized systems face in seeking to promote both reliability and competitive outcomes.

https://doi.org/10.1109/TEMPR.2023.3274227

Full Text

Abstract
Inefficient coordination between decentralized generation investment and centralized transmission planning is a significant barrier to achieving rapid decarbonization in liberalized electricity markets. While the optimal configuration of the transmission grid depends on the relative social costs of competing technologies, existing processes have not led to transmission expansion consistent with declines in the cost of wind and solar combined with increased estimates of the social costs of traditional thermal resources. This paper describes the negative feedback loop preventing efficient interconnection of new resources in U.S. markets, its connection to conceptual flaws in current resource adequacy constructs, and the ways in which it protects incumbent generators. To help resolve these issues, the paper recommends a shift to a “connect and manage” approach and outlines a straw proposal for a new financial right connected with transmission service. From a generator perspective, the effect of the proposed reforms is to trade highly uncertain network upgrade and congestion costs for a fixed interconnection fee. From a transmission planning perspective, the goal is to improve the quality of information about new generation included in forward-looking planning processes. Simulation on a stylized two-node system demonstrates the potential of the approach to facilitate a transition to clean technologies.

https://doi.org/10.1016/j.joule.2022.01.004

Working Paper

Abstract
Energy-only electricity markets, such as the Electric Reliability Council of Texas (ERCOT), rely on the decentralized investment decisions of market participants to lead to a resource mix providing an efficient level of reliability. During an exceptionally cold winter storm in February 2021, ERCOT experienced shortfalls on an unprecedented scale, with nearly half of the generation fleet experiencing outages at the peak. The depth of the resulting blackouts invites questions regarding the ability of systems relying on decentralized planning to appropriately prepare for and withstand rare events. Based on two mild assumptions, risk aversion among investors and incomplete risk trading, this paper offers an explanation for why decentralized markets are prone to underinvestment in resilience. We describe the nature of the incomplete risk trading that arises in the context of electricity markets and discuss potential remedies, including mandatory contracting obligations for retailers and compensation to end users for unserved energy.

https://doi.org/10.1109/MPE.2021.3104077

Abstract
The electric power system has historically been designed to provide reliable energy to loads by using a relatively small number of well-understood generators. The distinction between load, generation, and transmission resources has been quite clear. Most of the responsibility for planning and operating a system—building a highly reliable network from less reliable parts—has been with the system manager, whether that be a utility, a regional market operator, or some similar entity. Given this historical context, many experts were initially perplexed by the rapidly growing popularity of hybrid resources, which combine multiple technologies into a single entity. Rather than depending on a system operator to provide instructions to individual technologies, hybrid resources intentionally take on more operational responsibility by optimizing and scheduling their combined functions. Interconnection queues in many regions reveal a large and growing interest in hybrids, suggesting that project developers and investors see them as providing advantages.

https://pubsonline.informs.org/doi/10.1287/ijoo.2021.0051

Working Paper

Abstract
With wind and solar becoming major contributors to electricity production in many systems, wholesale market operators have become increasingly aware of the need to address uncertainty when forming prices. While implementing theoretically ideal stochastic market clearing to address uncertainty may be impossible, the use of operating reserve demand curves allows market designers to inject an element of stochasticity into deterministic market clearing formulations. The construction of these curves, which alter the procurement of reserves and therefore the pricing of both reserves and energy, relies on contentious administrative parameters that lack strong theoretical justification. This paper proposes instead to construct curves based on reserve valuations implicit in non-market reliability processes performed by system operators. The proposed strategy promotes greater consistency between commitment decisions and eventual prices, reducing the need for discriminatory uplift payments or enhanced pricing schemes to address non-convexity.

https://doi.org/10.1016/j.enpol.2020.112010

USAEE Working Paper

Abstract
In most liberalized electricity markets, flaws in short-term price formation have led to a “missing money” problem wherein average energy prices are too low to support an efficient level of capacity. Recent growth of wind and solar generation has exposed another category of flaws related to intertemporal constraints, such that energy prices are not volatile enough to support an efficient level of flexibility. In theory, electricity markets convey the value of flexibility through time-varying prices, encouraging market participants to invest in resources able to match production and consumption profiles to grid needs. Real-world market clearing procedures, however, make several simplifications that suppress volatility relative to the theoretical ideal. This paper describes five mechanisms by which current wholesale electricity market price formation may fail to provide full-strength incentives for flexible resources. Instead of restoring price volatility, market designers may choose to define flexibility products that act as a proxy for full-strength prices. However, these products cannot replicate theoretically ideal incentives precisely, with potentially important consequences for small-scale and distributed resources. The analysis could help guide ongoing efforts to ensure that systems have the capability to respond to growing variability and uncertainty in an efficient way.

EJOR Editors’ Award

https://doi.org/10.1016/j.ejor.2020.07.026

USAEE Working Paper

Abstract
Non-convex markets, such as those organized by electricity system operators, lack uniform clearing prices. In an attempt to align private and social costs when clearing these markets, operators have introduced a variety of price formation and uplift payment schemes. We investigate the impact that the choice of pricing scheme can have on generator entry and exit decisions. Our results suggest that despite the presence of fixed production cost elements, prices derived from marginal costs support the optimal capacity mix. The use of uplift payments to supplement these prices could lead to significant distortion of the capacity mix arising in competitive markets. Pricing schemes designed to reduce the need for uplift payments may at the same time reduce prices, leading to lower levels of capacity in equilibrium. Schemes intended to raise prices, to the extent they eliminate the need for discriminatory side payments, may allow system operators to support a higher level of capacity with less distortion to the capacity mix.

INFORMS ENRE Student Best Paper Award

https://doi.org/10.1038/s41560-019-0476-1

Full Text; Policy Brief

Abstract
In many liberalized electricity markets, power generators can receive payments for maintaining capacity through capacity markets. These payments help stabilize generator revenues, making investment in capacity more attractive for risk-averse investors when other outlets for risk trading are limited. Here we develop a heuristic algorithm to solve large-scale stochastic equilibrium models describing a competitive market with incomplete risk trading. Introduction of a capacity mechanism has an asymmetric effect on the risk profile of different generation technologies, tilting the resource mix towards those with lower fixed costs and higher operating costs. One implication of this result is that current market structures may be ill-suited to financing low-carbon resources, the most scalable of which have high fixed costs and near-zero operating costs. Development of new risk trading mechanisms to replace or complement current capacity obligations could lead to more efficient outcomes.

https://doi.org/10.1109/TPWRS.2017.2732921

Abstract
A basic principle of electricity market design is that cost allocation should follow cost causation as closely as possible. As renewable resources play a larger role in electricity generation, system operators have become increasingly concerned about costs related to variability in net load. While variable generation resources have attracted a great deal of attention along these lines, load is a larger source of variability in most systems. This paper introduces a Shapley value framework to assess the total system cost attributable to electricity market participants that either exacerbate or alleviate net load variability. Further, this paper investigates the extent to which these costs are adequately reflected in wholesale market prices. Numerical tests indicate that the cost of variability on the hourly time scale is in most cases internalized by market-integrated generators and buyers, mitigating concerns that variability imposes a socialized cost from ramping or cycling of thermal generators.

https://doi.org/10.5547/01956574.38.5.jmay

Executive Summary (PDF); Full Text (PDF); Online Appendix (ZIP)

Abstract
Current consensus holds that 1) passing through wholesale electricity clearing prices to end-use consumers will produce maximal efficiency gains and 2) simpler forms of time-varying retail rates will capture only a small portion of potential benefits. We show that neither holds in the presence of capacity costs typical in U.S. wholesale markets. Using an optimization model describing the short-term problem faced by an electricity retailer, we find hourly prices that optimally pass through capacity costs. We estimate benefits for a retailer using these prices as well as optimal configurations of a number of time-varying rate structures. Testing a range of realistic assumptions, we find that in the absence of a well-designed demand charge, passing through clearing prices may miss up to three quarters of the benefits possible from optimal hourly prices. By contrast, a simpler critical peak pricing structure enables retailers to achieve approximately two-thirds of the total possible benefits.

Joint with Josh Macey

Working Paper

Abstract
Many liberalized electricity markets use capacity mechanisms to ensure that sufficient resources will be available in advance of operations. Recent events have called into question the ability of capacity mechanisms to provide sufficient incentives for reliability. A core resource adequacy challenge is that, given the high value of reliable electricity, penalties for non-performance on capacity obligations are lower than what theory would suggest is economically efficient. Weak non-performance penalties give suppliers an incentive to overstate their contributions to reliability. However, stronger penalties will often not be enforceable because suppliers can discharge their obligations through bankruptcy. In principle, system operators can mitigate the effect of weak incentives by conducting accreditation studies that limit the size of the capacity obligation taken on by suppliers. However, political, economic, and technical factors lead to accreditation values that are systematically too high. We discuss the ensuing threats to reliability, the difficulty of implementing “pure market” solutions, the inefficient around-market actions that system operators may take in response, and the potential for the size of the effects to grow with a shift to variable renewable resources.

Joint with Han Shu

Working Paper

Abstract
Disputes over cost allocation can present a significant barrier to investment in shared infrastructure. While it may be desirable to allocate cost in a way that corresponds to expected benefits, investments in long-lived projects are made under conditions of substantial uncertainty. In the context of electricity transmission, uncertainty combined with the inherent complexity of power systems analysis prevents the calculation of an estimated distribution of benefits that is agreeable to all participants. To analyze aspects of the cost allocation problem, we construct a model for transmission and generation expansion planning under uncertainty, enabling the identification of transmission investments as well as the calculation of benefits for users of the network. Numerical tests confirm the potential for realized benefits at the participant level to differ significantly from ex ante estimates. Based on the model and numerical tests we discuss several issues, including 1) establishing a valid counterfactual against which to measure benefits, 2) allocating cost to new and incumbent generators vs. solely allocating to loads, 3) calculating benefits at the portfolio vs. the individual project level, 4) identifying losers in a surplus-enhancing transmission expansion, and 5) quantifying the divergence between cost allocation decisions made ex ante and benefits realized ex post.