CS35: Electricity Market Design and Regional Integration

IAEE_2026_Reforming markets to allow customers to express their valuation of reliability.docx
Electricity markets are increasingly misaligned with the technological and economic realities of modern power systems. Despite rapid digitalization, distributed energy resources, and advanced demand-side capabilities, wholesale electricity market designs continue to rely on stylized textbook constructs and very old fashioned about final consumers' ability to express their preferences as to the reliability they are willing to pay for - which is most notable in the continued use a single Value of Lost Load (VoLL) parameter applied uniformly across heterogeneous consumers. This paper asks: how can electricity markets be redesigned to better reflect and operationalize consumers' differentiated willingness to pay for reliability?

This paper develops a detailed computational model of a regional electricity market in South America to assess the benefits of introducing flexible month-ahead energy commitments with real-time settlement. The study focuses on the Southern Cone integration initiative known as SIESUR, comprising Brazil, Argentina, Chile, Bolivia, Paraguay, and Uruguay. These countries are already interconnected through a network of bilateral transmission links, yet cross-border electricity exchanges remain limited relative to the region's technical and economic potential. Strengthening international electricity transactions is critical for improving security of supply, reducing system-wide operational costs, and enhancing the integration of variable renewable resources.

A defining characteristic of the SIESUR region is its high reliance on hydropower, particularly large reservoir-based systems with significant intertemporal storage capabilities. The stochastic nature of inflows and the strong seasonal patterns in hydro availability create substantial value in coordinated, forward-looking scheduling. This hydrological dominance motivates the organization of month-ahead commitments that explicitly capture water opportunity costs and intertemporal trade-offs, while allowing deviations to be efficiently balanced in a real-time market. Such a design aims to combine medium-term coordination with short-term flexibility.

The paper implements an explicit representation of the regional market using the IARA computational tool, incorporating hydrothermal dispatch, transmission constraints, and cross-border exchanges. By comparing alternative market designs, the study quantifies the economic gains from flexible month-ahead commitments, evaluates distributional effects among countries, and assesses impacts on price convergence and system reliability. Results provide policy-relevant insights into how enhanced regional coordination and improved market architecture can unlock the full benefits of hydropower complementarities across SIESUR.

This paper develops a framework to analyse policy-cost avoidance in liberalised retail electricity markets undergoing electrification. Many systems recover fixed policy costs-renewable support, social obligations, decarbonisation levies-through volumetric charges on consumption. While these costs are fixed at the system level, consumers and suppliers can reduce their share through behind-the-meter technologies, self-consumption, storage, or avoidance-enabling retail contracts. Such actions erode the levy base without reducing aggregate costs, raising per-unit charges for remaining consumers.
The paper shows this mechanism generates a fiscal externality that competitive retail markets do not internalise. Suppliers compete by offering products that facilitate private bill reduction, amplifying avoidance incentives beyond the social optimum. Simultaneously, volumetric policy charges inflate the private marginal cost of electricity, causing inefficiently low electrification even when it yields positive net social benefits. Avoidance exceeds socially optimal levels whenever private savings from reduced levies exceed the true system value of underlying technologies.
A welfare decomposition identifies two inefficiency sources: real resource costs devoted to avoidance that merely redistributes a fixed burden, and foregone gains from socially beneficial electrification. Extending the model dynamically, the paper demonstrates that policy-cost avoidance exhibits strategic complementarity: higher avoidance reduces the levy base, raises per-unit charges, and strengthens further avoidance incentives. This feedback can generate multiple steady states and self-reinforcing dynamics absent regulatory intervention.
The paper concludes that policy-cost recovery design is a first-order policy problem. While partial fiscal reforms mitigate distortions, the underlying externality persists for any fixed cost recovered volumetrically. Efficient decarbonisation requires tariff designs balancing efficiency, equity, and political feasibility, rather than relying on retail competition alone to deliver socially optimal outcomes.

Over the last twenty-five years, several electricity markets in the United States have shifted from centrally planned investment to market-based procurement of new generation capacity to achieve long-run efficiency gains and shift investment risk from customers to generation companies. Many of these regions also rely on long-term contracts to support investment: for example, several states have initiated competitive procurement for long-term power purchase agreements with wind, solar and other zero- or low-carbon technologies to meet deep decarbonization goals. Power producers in these regions thus respond to economic incentives that operate on two levels: one that shapes investment choices and another that governs operational decisions once those resources are in service. If not carefully designed, long-term contracts may produce undesirable short-term outcomes, including dispatch distortions, excess curtailments and surplus renewable investment in transmission-constrained regions. 
We explore the efficient integration of long-term contracts with short-term wholesale markets using two-stage equilibrium models under uncertainty, risk aversion and high renewable energy penetration. The first model represents an "energy only" electricity market design with improved scarcity pricing through operating reserve demand curves. Under this structure, first-stage decisions regarding generation and storage capacity respond solely to scarcity pricing incentives, while second-stage outcomes reflect hourly dispatch choices. In the second model, we introduce a market for financial long-term, fixed-price contracts for energy based on a specified production profile. Therefore, first-stage capacity expansion reflects incentives from both scarcity-based prices and forward contracts. The second stage continues to represent a short-term energy market focused on operational efficiency and reliability. Both models are run on an 8-zone test system representing ISO New England, and account for uncertainty in electricity demand, wind and solar generation.