CS21: Oil and Gas Markets: Resources, Networks and Regulation

The implementation of the International Maritime Organization's global sulfur cap (IMO 2020) marked a major structural shift in the maritime sector by reducing the allowable sulfur content in marine fuels from 3.5% to 0.50% by weight for ships operating outside designated emission control areas. This regulatory change fundamentally reshaped marine fuel demand and pricing, with spillover effects extending beyond the maritime sector to related energy markets.
This paper examines how IMO 2020 altered the degree of market integration between marine and land-based fuel markets. In particular, we study the price dynamics linking marine fuels and transportation diesel, focusing on the interaction between Marine Gas Oil (MGO), Very Low Sulfur Fuel Oil (VLSFO), Intermediate Fuel Oil (IFO) 380, and on-road diesel. The analysis uses New York marine fuel price data spanning June 2015 to June 2025, combined with monthly U.S. transportation diesel prices from the Energy Information Administration. By covering both the pre- and post-IMO 2020 periods, the study provides evidence on how sulfur regulation reshaped cross-market price linkages between marine and terrestrial fuel markets.

In January 2026, Brazilian Regulatory Commission for Oil & Gas (ANP) introduced a new method for valuing the Regulatory Asset Base (BRA) applicable to pipelines that have undergone the transition from a negotiated pricing regime to a regulated pricing regime in Brazil.
The Recovered Capital Methodology (RCM) calculates the residual value of assets based on the recovery trajectory of invested capital over time, incorporating investor returns. This approach contrasts with methods traditionally used in economic regulation, which are based on the regulatory depreciation of assets to calculate the residual value of the regulatory base - Historical Cost and Replacement Cost methods.
The ANP's inspiration was the experience of Australia, where RCM has been used since 2017 for the valuation of gas transportation assets in unregulated pipelines, as a reference for bilateral negotiations and in arbitration processes involving access to these pipelines. This framework was conceived and applied in an institutional environment distinct from Brazilian tariff regulation and the method is not universally accepted, even in Australia. 
In this context, this article seeks to evaluate the applicability of the method within the Brazilian environment, also carrying out comparisons and cost-benefit analyses in relation to the traditional historical cost and replacement value methods. The impacts on transmission companies, in terms of regulatory EBITDA, and on network users, in terms of tariff variations, will be assessed. 
Finally, a risk and impact assessment will be carried out, via international benchmarks and comparisons with other regulated sectors, with a view to contribute to the natural gas market development in Brazil.

Many natural gas markets opening to third-party access share two structural features: network constraints that limit arbitrage and concentrated supply with a dominant firm. This paper investigates how these elements shape hub price formation and delivered costs. The research question is: can a dominant supplier sustain higher prices by strategically withholding output, and how do pipeline constraints and market design (e.g., market areas/virtual trading points) affect this ability?


We develop a general agent-based network equilibrium model for a liberalizing gas market with a dominant supplier. The physical system is represented as a pipeline grid of nodes and arcs, preserving flow-balance constraints, capacity limits, and transportation costs/tariffs. Producers and shippers interact strategically under Nash–Cournot behavior, and equilibrium is computed as a mixed complementarity problem / variational inequality, obtained by combining each agent's Karush–Kuhn–Tucker conditions with network feasibility and market-clearing constraints at trading hubs. The formulation follows established complementarity-based approaches for gas markets where strategic suppliers can influence inverse demand while other segments remain competitive.


We evaluate the framework through scenarios that vary (i) the dominant firm's market share and conduct (Cournot), (ii) congestion levels and transfer capacity across key corridors, and (iii) the degree of market integration via alternative hub/market-area definitions and incremental interconnection capacity. Outputs include equilibrium hub prices, nodal price spreads, congestion rents, quantities withheld, and welfare impacts.


To demonstrate empirical tractability, we test the model using Brazilian network, supply, and demand data as an illustrative case consistent with the target setting due to its integrated grid and historically dominant supplier. Results are expected to show that withholding is most effective when congestion limits entry and arbitrage, producing persistent price differentials, while added transfer capacity and more integrated trading arrangements reduce the profitability of withholding and lower equilibrium prices, informing infrastructure prioritization and pro-competition reforms.

South Africa's transition towards higher penetrations of variable renewable energy (VRE) requires increased electricity system flexibility to maintain reliability and supply adequacy, particularly as 8 GW of coal-fired generation capacity is scheduled for decommissioning by 2030. In the absence of commercially mature long-duration energy storage, natural gas is identified in national planning frameworks as a source of firm dispatchable capacity to support system flexibility.
The deployment of gas-fired generation introduces operational and investment interdependencies between electricity and natural gas infrastructure. Short-term power imbalances arising from renewable variability are balanced by gas-fired generation, directly influencing gas demand, system operation, and infrastructure utilisation. Gas-fired power plants depend on gas supply infrastructure, including LNG import terminals, pipelines, and storage facilities, while gas infrastructure relies on electricity for compression and operation. Gas offtake from the power sector must be coordinated with industrial gas demand, as both rely on shared supply and delivery infrastructure. These interactions create bidirectional dependencies, where electricity system conditions influence gas system operation and expansion, and gas supply availability and infrastructure constraints affect power system dispatch and generation investment decisions. These interactions are relevant in South Africa in the context of the anticipated "gas cliff", with declining pipeline imports from Mozambique and domestic offshore gas production, resulting in increased reliance on LNG imports and associated infrastructure. However, existing national-scale electricity planning does not explicitly represent gas–electricity interdependencies, limiting the ability to assess how gas supply availability, infrastructure constraints, and long-term LNG contractual obligations, including minimum offtake requirements, may influence generation investment decisions, system operation, electricity prices, and emissions trajectories. This study establishes input assumptions and model configurations for a combined capacity expansion planning (CEP) and unit commitment (UC) framework to represent gas infrastructure, supply, and contractual characteristics in long-term power system planning.
 

Oil has been the largest energy source that powers economic growth. Lately, carbon emissions and the issue of climate change have put the industry in a bind. Energy transition has started and the paths are clear: replace fossil fuels or rely on carbon capture. Non-profit organizations have urged countries to move towards cleaner and more sustainable energy sources with compiled data and forecasts confirming this course of action. The shrink of the oil industry due to energy transition seems to be inevitable. Saudi Arabia is one of the largest producers of crude oil with 60% of the economy based on oil and gas sector. In hindsight, the idea of energy transition should not sit well with the Kingdom. However, in reality, the Kingdom is actually quite aggressive with its renewable energy development. Of course, having one of the highest solar irradiations on the planet helps, but throwing away the huge welfare in crude oil market seems to be counter intuitive. Another possible explanation is that energy transition would actually help to get rid of high-cost oil producers creating a more concentrated crude oil market. This study found empirical evidence that the growth in renewable energy generation improves the Kingdom's market power in the short run using datasets from 2015 to 2025. For the long run, the effect is statistically insignificant.