CS16 - Energy Transition

India is the world's third-largest electricity producer, consumer, and carbon emitter. The country faces the dual challenge of meeting rapidly growing electricity demand while aligning with its net-zero commitment by 2070. Although renewable energy deployment has accelerated in India, the feasibility of deep decarbonization pathways remains uncertain due to concerns related to grid reliability, dispatchability, and large-scale sectoral electrification.
This study employs the OSeMOSYS long-term energy system optimization framework to evaluate India's electricity transition under three contrasting scenarios: a Business-as-Usual (BAU) pathway, an Emission Reduction Scenario (ERS) targeting a 60% emissions reduction by 2050, and a Deep Decarbonization and Dispatchability Scenario (D3S) targeting a 90% reduction while explicitly enforcing minimum firm capacity requirements.
The results reveal that while moderate decarbonization can be achieved through rapid renewable deployment and partial electrification, deep decarbonization without compromising system reliability requires substantial investment in dispatchable low-carbon technologies, including nuclear power, hydropower, biomass-based generation, and carbon capture–equipped thermal plants. The D3S pathway enables near-complete emissions reduction but entails significantly higher capital investments, rising marginal abatement costs, and emerging resource constraints as the system approaches full decarbonization. The findings underscore that renewable energy expansion alone is insufficient to achieve reliable deep decarbonization in India. Early planning for nuclear power, readiness for carbon capture deployment, and a diversified portfolio of firm low-carbon resources are critical to ensuring long-term grid resilience while aligning India's electricity system with global 1.5°C climate targets.

The global energy transition is reshaping electricity supply industries worldwide. This paper examines how the large-scale integration of renewable energy, at both utility and distributed scales, catalyses broader structural reform of electricity supply industries, using South Africa's ongoing transition away from a coal-dominated monopoly as a case study.
Drawing on South Africa's ongoing transition away from a vertically integrated, coal-dominated monopoly toward a decarbonised, competitive, and multi-participant electricity market, the paper identifies three interconnected dimensions of transformation common to ESIs undergoing similar transitions. First, the integration of variable renewable energy fundamentally reshapes system operational priorities, shifting value away from bulk energy provision toward flexibility, dispatchable capacity, and ancillary services, qualities that were historically implicit and unpriced in centrally planned systems. Second, the geographic concentration of renewable resources, often distant from established generation and load centres, necessitates significant transmission infrastructure investment and introduces new questions around cost allocation, locational pricing, and network access. Third, the rapid growth of distributed generation, particularly behind-the-meter solar PV, exposes critical misalignments between prevailing volumetric retail tariff structures and the fixed-cost reality of network infrastructure, creating regressive cross-subsidies and undermining the financial sustainability of incumbent utilities.
The paper argues that the energy transition in emerging markets is not merely a technological substitution but a comprehensive renegotiation of technical operations, financial arrangements, and social contracts, particularly in societies characterised by persistent inequality and low institutional trust. South Africa's experience offers transferable lessons for other emerging markets, including India, Brazil, and Kenya, navigating analogous tensions between accelerating renewable deployment, utility financial viability, and energy affordability. 

This study compares two flexibility pathways in a carbon-neutral power system targeting 2050: a renewable energy–storage–oriented pathway and a brownfield small modular reactor–oriented pathway. A cost-minimizing capacity expansion model determines the optimal generation mix, which is then evaluated through an annual unit commitment simulation incorporating investment and operating costs, fuel prices, carbon constraints, hourly demand, and renewable variability. Both pathways achieve coal phase-out after 2040 and satisfy carbon neutrality, load, and reserve requirements in 2050, yet exhibit distinct operational characteristics. The renewable–storage pathway manages variability primarily through storage but increases baseload nuclear output fluctuations and reveals reserve vulnerabilities under extreme net-load conditions. In contrast, the small modular reactor pathway provides carbon-free firm capacity and improves dispatch stability by distributing flexibility across gas, storage, and small modular reactor units. Sensitivity analysis further examines the cost conditions under which the optimal capacity structure shifts, identifying thresholds in small modular reactor capital costs that alter the preferred pathway. The results indicate that while small modular reactors enhance operational stability in dispatch, higher penetration reduces renewable energy accommodation, leading to increased curtailment and lower overall system energy efficiency. These findings underscore the trade-off between dispatch reliability and renewable integration in designing a cost-effective and robust carbon-neutral power system.

South America's energy systems exhibit strong demand heterogeneity across geographies and time, driven by industrial load profiles, seasonality, and policy constraints, while significant portions of gas pipelines and power transmission assets operate below capacity. This paper proposes a corridor-based economic framework to identify and value regional energy exchange opportunities across Argentina, Bolivia, northern Chile, and Brazil, focusing on how complementary demand profiles and existing infrastructure can be coordinated to reduce curtailment, improve security of supply, and lower total system costs.
We address three questions: (i) which cross-border corridors deliver the highest expected welfare gains under plausible demand and availability scenarios; (ii) how much unrealized value is attributable to physical bottlenecks versus regulatory and contractual frictions; and (iii) which market and regulatory instruments can unlock benefits with minimal new CAPEX. The approach combines a simplified network representation of gas and electricity interconnections with scenario-based simulations of dispatch and transfer, using publicly available system information on capacity, operational constraints, and market or dispatch indicators where available. We complement the quantitative screening with an institutional feasibility layer that evaluates access rules, tariff structures, capacity allocation mechanisms, and coordination requirements among operators and regulators.
The framework is intended to support a practical prioritization of "no-regrets" integration actions, such as standardized interruptible and firm exchange products, transparent capacity release, and harmonized operational protocols, before committing to major expansion projects.

The global shift toward low‑carbon fuels is intensifying interest in renewable methanol, particularly from biomass and biogas, which are abundant, geographically distributed, and compatible with existing industrial infrastructure. This paper provides a comprehensive assessment of the technical pathways, economic considerations, and deployment strategies for converting renewable carbon into methanol.
Biomass‑to‑methanol production is examined primarily through gasification, which generates synthesis gas requiring conditioning and optimization to maximize carbon conversion. The analysis explores syngas cleanup, adjustment of H₂/CO ratios, and integration with renewable hydrogen to enhance methanol yield. Emerging technologies-including biomass pyrolysis with downstream reforming and hybrid systems combining bio‑carbon with external hydrogen-are evaluated for readiness, scalability, and potential to reduce lifecycle emissions.
Biogas‑to‑methanol pathways are reviewed with emphasis on upgrading raw biogas and reforming methane–CO₂ mixtures. Steam reforming, dry reforming, and combined reforming are compared in terms of syngas composition, CO₂ utilization efficiency, and catalyst durability. The paper also assesses direct CO₂ hydrogenation using renewable hydrogen, positioning it within broader power‑to‑fuel strategies aimed at maximizing carbon circularity.
A comparative analysis highlights the advantages of biomass and biogas routes over fossil‑based methanol and alternative renewable pathways. Benefits include significant lifecycle greenhouse‑gas reductions, alignment with waste‑management and circular‑economy goals, and suitability for distributed production hubs that reduce logistics burdens.
Economic evaluation through levelized cost of methanol modeling identifies feedstock procurement, capital expenditure for conversion technologies, catalyst costs, and hydrogen integration as key cost drivers. Sensitivity analyses illustrate the influence of carbon pricing, renewable fuel credits, and feedstock variability on project economics.
The paper concludes with KBR's integrated approach, showcasing reforming catalysts, proprietary methanol synthesis technologies, and digital optimization tools. Case studies demonstrate modular, scalable plant configurations that support global deployment of renewable methanol as a cornerstone of the energy transition.