CS30: Electricity Markets

Colombia's electricity sector combines a hydro-based generation mix with a liberalized wholesale market in which energy prices are determined through generators' price and quantity bids. This design contrasts with the cost-based dispatch schemes adopted in most South American countries, where prices reflect regulated production costs. In Colombia, hydrological variability, especially during El Niño and La Niña events, strongly influences generators' opportunity costs and bidding behavior. During periods of abundant inflows, water's opportunity cost is low and agents' bids tend to fall; under drought conditions, opportunity costs rise, pushing bids upward and increasing reliance on more expensive thermal generation.
Because bids incorporate not only production costs (or water values) but also risk premiums and strategic markups, distinguishing cost-driven components from discretionary pricing is challenging, particularly in hydro-dominated systems where estimating water values is complex. To approximate generator markups in the Colombian market, this study develops a historical counterfactual system dispatch using a cost-based methodology: thermal units are evaluated using their fuel and variable costs, while hydro units are assigned model-derived water values. Deviations between observed market prices and the counterfactual cost-based prices are interpreted as potential markups.
The analysis covers a ten-year period and examines how markups evolve across different hydrological regimes. Results show that markups increase substantially during El Niño episodes, reflecting tighter system conditions, higher uncertainty, and a greater ability of agents to exercise market power. Regression models identify the El Niño index, hydrological inflows, and spot prices as key explanatory variables for markup behavior.
A structural break emerges in late 2023, coinciding with the government's proposal of a price cap to generators' bids. Although not implemented, the regulatory threat is associated with a statistically significant reduction in markups, suggesting that regulatory expectations can alter bidding behavior in hydro-dependent, bid-based electricity markets.

South Africa is establishing a competitive wholesale electricity market (SAWEM) after over a century of vertically integrated, state-owned monopoly supply. The Electricity Regulation Amendment Act (2024) mandates vesting contracts between the Central Purchasing Agency and Eskom's generators and distributors to manage this transition. This paper identifies and analyses the key design tensions that have emerged in initial proposals for vesting contract design, which seek to balance multiple, partially competing, objectives in a market dominated by a single incumbent generator.
Vesting contracts offer revenue certainty, support market liquidity, and constrain market power during the early years of a new spot market. Yet their design involves inherent tensions that, if poorly resolved, risk undermining the market outcomes they are intended to support. These include: the tension between providing full cost recovery for the incumbent generators and preserving cost-reflective price signals in the day-ahead market; between protecting downstream participants against price volatility and exposing them to signals that incentivise participation of more efficient generators and providers of demand response; between enabling efficient retail competition and protecting incumbent retailers from revenue loss due to uneconomic bypass of costs related to subsidies and the provision of centralised generation capacity; between accommodating legacy fuel and capacity commitments and ensuring these do not distort merit-order dispatch or delay exit of uneconomic plant; and between open-ended contract duration linked to dominance assessments and the need for a predictable, time-bounded transition to seed a futures market.
The paper examines these tensions through a framework informed by international experience, including the England and Wales Pool reforms, the Australian National Electricity Market and the Irish Single Electricity Market, and applies this to the frameworks proposed for SAWEM. It concludes by discussing critical design principles for vesting contracts in jurisdictions undertaking reform from a position of incumbent dominance.

The growth of distributed energy resources and Energy Communities (ECs) is reducing electricity drawn from the grid, thus lowering volumetric revenues for distribution system operators (DSOs) who must recover fixed network costs through higher tariffs. This creates a trade-off between ensuring DSOs' financial viability, keeping ECs economically attractive, and avoiding unfair cost increases on regular consumers that could trigger a utility death spiral through a feedback loop of declining demand and rising network charges. This paper investigates how redistributing DSOs' revenue losses across volumetric, capacity-based, and fixed tariff components affects EC formation decisions and equitable cost allocation. Focusing on capacity-based and hybrid tariff structures, the study contributes novel insights by systematically analysing which tariff designs effectively reconcile DSO revenue requirements, consumer welfare, and fair cost-sharing between active and passive network users. Using a bill-minimisation framework with network cost recovery constraints, DSO revenues under EC and non-EC scenarios are simulated across 100 regulated tariff designs generated through Latin Hypercube Sampling. Tariff outcomes are assessed through revenue recovery performance, welfare distribution, and cross-subsidies, with fair designs identified using cooperative game-theoretic benchmarks including Shapley value allocations. Preliminary findings suggest that capacity-based and hybrid tariff structures outperform purely volumetric designs by enhancing overall welfare and limiting cross-subsidisation between consumer groups, while preserving the economic attractiveness of EC participation. The results will provide practical policy recommendations for tariff adjustments and technical constraints that balance DSO's financial needs with EC promotion objectives, while ensuring fair cost distribution during the transition toward decentralised energy systems.

@page { size: 8.5in 11in; margin: 0.79in } p { margin-bottom: 0.1in; line-height: 115%; background: transparent } Transmission cables between hydropower rich Norway and windpower rich Denmark (among others) have been heavily discussed as these cables are seen as exporting cheap power and "importing" high prices, especially after electricity prices spiked in 2022. 
The overall gains from international trade are often overshadowed in discussions by more specific and visible losses. In a transmission constrained electricity system some of the gains of trade are captured in congestion rents. In a hydropower a price increases will increase the water value resulting in an upward shift in the supply curve. This paper investigates the distributional impacts of this price effect in a simplified simulation model of two countries with different technologies and limited transmission capacity.
The baseline simulation has a single transmission line. The average price in Denmark is substantially higher than in Norway. As the number of lines increases, the prices converge and the frequency of water spills and curtailment in Norway decreases.
For Denmark consumers are gaining and producers are loosing compared to the baseline case. The distributional effects for Norway are reversed. With a moderate capacity on the transmission line the price increase in Norway is substantial and with a higher average price than in Denmark. The export to Denmark occurs at high prices while the import at low prices is not enough to lower the prices. The periodic high prices has increased the water value and shifted the supply curve. The low prices in Denmark are not benefiting Norwegian consumers. As the transmission capacity increases, low periodic prices in Denmark will also clear the market in Norway. Sensitivity analysis shows that the magnitude of this effect depends critically on wind production capacity in Denmark. 

Electricity market liberalisation is typically analysed in systems with surplus capacity, diversified ownership, and institutional stability. However, when reforms occur under electricity system stress conditions, such as supply inadequacy, dominant incumbency, financial strain, and weak investment signals, transitional instruments can be introduced to stabilise revenues and mitigate market power during the shift from vertical integration to wholesale competition. The operational and investment implications of these instruments, including vesting contracts, centralised procurement structures, price caps, and legacy cost recovery charges, are insufficiently quantified. This paper uses a fundamental unit commitment and economic dispatch–based electricity market model with explicit technical, operational, and network constraints to evaluate how transitional market design choices proposed in South Africa's market reform affect price formation, generator revenues, investment incentives, and reliability outcomes. By simulating outcomes across multiple reliability and market design scenarios for South Africa, the analysis quantifies the effects on scarcity price frequency, entry signals for flexible generation, the incumbent utility's revenue, and legacy system costs arising from the transitional market mechanisms. Results indicate that the proposed transitional arrangements can materially distort short-run price signals and weaken long-run investment incentives. While revenue-stabilising mechanisms reduce price variability in the short term, they can delay the entry of new technologies and increase long-run adequacy costs if not aligned with credible reliability standards. The findings demonstrate that the design of these transitional mechanisms materially shapes the trajectory towards a competitive market and ultimately the reliability of the power system.