CS6: Energy Market Design

The integration of the natural gas and electricity industries is a strategic pillar for Brazil's energy security and infrastructure development. Both industries are structured as physical networks with deep interdependencies: gas consumption for power generation is crucial for the country's energy supply, while thermal demand accounts for approximately 36% to 50% of the national natural gas demand during peak periods. Historically, the Brazilian power matrix – dominated by hydropower – has utilized gas-fired thermal power plants primarily as a flexible backup for dry periods. However, auction designs prioritized minimizing short-term fixed costs, which incentivized the expansion of a thermal power fleet disconnected from the integrated transport network – relying instead on exclusive LNG terminals or "well-to-wire" arrangements. This trend led to a fragmented infrastructure, where the power sector tries to avoid natural gas transport costs, which simultaneously increasing tariffs for other gas users (industrials), potentially triggering a "death spiral" for the gas grid.
This trend of infrastructure fragmentation has reduced the overall reliability and resilience of both industries. Disconnected projects fail to benefit from the physical and commercial flexibility of an interconnected grid, which provides access to multiple gas sources and commercial opportunities. The massive penetration of VREs has fundamentally transformed the system's demand for flexibility. Brazil now requires a new profile of operational flexibility to handle the "duck curve", which context demands that gas-fired plants provide rapid response and peaking capabilities, which are more efficiently managed through an integrated network that offers instantaneous and flexible gas supply.n The paper evaluates the evolution of the Capacity Reserve Auctions from the 2021 edition to the proposed 2026 guidelines, arguing for a regulatory shift from a partial equilibrium approach to an integrated general equilibrium vision that recognizes the physical and contractual interdependency of power and gas networks industries.

As electricity systems decarbonize and electrify, a rising share of costs is driven by fixed network investments (grid expansion, resilience, and integration of new resources). This shift strengthens the regulatory case for tariff rebalancing-recovering network costs through higher fixed charges while reducing volumetric rates to better align marginal incentives. Yet the demand implications remain contested. A central debate is whether households respond to marginal prices or instead to average prices and overall bill perceptions under complex tariffs, with first-order consequences for efficiency equity of these reforms.
We study a major residential tariff redesign implemented in Tucumán (Argentina) in January 2021 that sharply increased fixed charges, reduced regulated volumetric rates. Using administrative billing records for approximately 120,000 monthly-billed residential customers from 2019–2022, we exploit tariff-schedule-driven heterogeneity in predicted changes in bill composition. We construct a pre-determined continuous treatment intensity by simulating bills under the pre- and post-reform schedules and computing each household's predicted increase in the fixed-charge share of the bill based on pre-reform consumption histories and social-tariff eligibility. We then estimate two-way fixed-effects and event-study models that interact post-reform (event-time) indicators with this intensity measure, absorb common shocks with month-by-year fixed effects, and test for differential pre-trends.
Preliminary estimates indicate a positive causal effect of the reform on residential electricity consumption. We further evaluate heterogeneous effects by baseline consumption levels and by income status, proxied by social-tariff eligibility and a census-tract vulnerability index.
To the best of our knowledge, this is among the first studies in Latin America to combine full-population administrative billing data with a structural, tariff-simulation-based exposure design to identify how higher fixed charges affect residential electricity demand under tariff rebalancing.

Brazil's natural gas market liberalization drove a structural transformation, encouraging new entrants and fostering competition with the emergence of independent shippers, traders and import opportunities. Thus, short-term transactions grew rapidly, increasing liquidity, signaling the consolidation of a more dynamic and integrated market. In this context, the impact of transmission tariff multipliers became an increasingly relevant regulatory parameter for the market's development.
International literature on transportation charge design emphasizes economic efficiency and cost recovery as core regulatory/economic objectives and is widely discussed considering various tariff methodologies, including the multipliers' application (Mosácula et al., 2018; Mosácula et al., 2019). Yet literature offers limited assessment of multiplier impacts (Çam; Lencz, 2021).
Therefore, the research question is whether the current gas transportation multiplier structure promotes economic efficiency and supports cross-border energy integration within South America.
Considering Brazil's market and reported multiplier transportation revenue, as well as institutional positions submitted in recent public consultations, in the last five years, multipliers accounted for nearly BRL 300 million, from an increase in short-term transportation contracts, including, but not highly representative in market share, gas imports from Argentina and Bolivia. 
Also, natural gas demand has remained stable and market agents are requesting that multipliers should be defined to a maximum of 1.15 to stimulate demand and short-term trading.
The transportation cost share in the final price composition is estimated to be at least 10%, not including the effect of multipliers or sanctions. Considering every other variable the same, that results in a tariff impact of up to 6,1% from multipliers.
This scenario indicates that multipliers may influence competitiveness and liquidity but have not yet generated new market demand. Regionally, aligning pricing structures and transportation incentives among Brazil, Bolivia, and Argentina could be proven to be more effective to enhance cross-border flows and advance South American gas market integration.

The accelerated expansion of variable renewable energy (VRE) has reshaped electricity market design across multiple jurisdictions. As renewable penetration increases, curtailment shifts from an operational adjustment mechanism to a structural feature affecting risk allocation, price signals, and long-term investment incentives. In this context, the integration of renewables raises fundamental questions about how electricity markets allocate system-level risks.
This paper examines how structural changes in curtailment dynamics interact with market design and regulatory credibility in the Brazilian electricity system, which, like many others, is undergoing a rapid energy transition. Drawing on the regulatory commitment framework developed by Levy and Spiller (1994), the analysis distinguishes between technical foreseeability and institutional predictability in the allocation of curtailment-related costs. 
The Brazilian case provides an illustrative contribution to the broader global debate on renewable integration. Following a decade of rapid expansion in wind, utility-scale solar, and distributed generation, curtailment levels increased sharply from 2023 onward, prompting legislative intervention. Law 15,269/2025 introduced compensation mechanisms for system and transmission-related curtailment events while maintaining market-based and energy-related restrictions as generators' responsibility.
The paper argues that the new framework represents a partial redesign of risk allocation within the electricity market. Nevertheless, it leaves residual regulatory uncertainty due to the exclusion of certain categories of events and its reliance on subsequent regulatory implementation. 
The Brazilian experience contributes to discussions on how electricity market design can reconcile accelerated renewable integration with regulatory credibility and efficient long-term investment incentives. It suggests that regulatory credibility does not require institutional rigidity; rather, it may depend on explicit and general rules capable of stabilizing risk allocation when systemic conditions materially change.

Germany is increasingly facing internal transmission congestion as renewable generation expands rapidly in the north while major load centres remain in the south and west. Under the current zonal pricing system, these bottlenecks are not reflected in day-ahead prices because internal grid constraints are ignored; congestion is instead managed ex post through redispatch. This raises doubts about whether the existing market design reflects physical conditions and true system costs. Two main remedies are discussed in the literature: splitting the current bidding zone or adopting Locational Marginal Pricing (LMP), i.e., nodal pricing. However, a quantitative comparison between zonal pricing and a highly resolved nodal system that also accounts for planned German grid reinforcements in the Ten-Year Network Development Plan (TYNDP) remains limited.
This study addresses that gap by quantifying how new TYNDP projects affect key power-system metrics under different pricing regimes. We develop an hourly dispatch model of the German electricity system with around 800 nodes and a full DC load-flow representation of the transmission network. We assess four scenarios: (1) zonal pricing (status quo), with a uniform DE/LU price and no internal constraints; (2) nodal pricing, where dispatch and prices are co-optimised subject to network limits; (3) zonal pricing with TYNDP, testing whether planned reinforcements reduce congestion under the current market design; and (4) nodal pricing with TYNDP, examining how LMP interacts with the future grid topology.
Across scenarios, we evaluate dispatch patterns, spatial price variation, redispatch volumes and costs, congestion rents, and renewable curtailment. We expect nodal pricing to expose persistent structural bottlenecks-especially along north–south corridors-and to produce spatial price differentials that better reflect network scarcities. While TYNDP reinforcements should reduce redispatch needs, preliminary results indicate they will not eliminate internal congestion, suggesting grid expansion alone may be insufficient without complementary market-design changes.