CO2 Price Research Articles

Feasibility of Green Hydrogen-Based Synthetic Fuel as a Carbon Utilization Option: An Economic Analysis

Singapore has committed to achieving net zero emissions by 2050, which requires the pursuit of multiple decarbonization pathways. CO2 utilization methods such as fuel production may provide a fast interim solution for carbon abatement. This paper evaluates the feasibility of green hydrogen-based synthetic fuel (synfuel) production as a method for utilizing captured CO2. We consider several scenarios: a baseline scenario with no changes, local production of synfuel with hydrogen imports, and overseas production of synfuel with CO2 exports. This paper aims to determine a CO2 price for synfuel production, evaluate the economic viability of local versus overseas production, and investigate the effect of different cost parameters on economic viability. Using the current literature, we estimate the associated production and transport costs under each scenario. We introduce a CO2 utilization price (CUP) that estimates the price of utilizing captured CO2 to produce synfuel, and an adjusted CO2 utilization price (CCUP) that takes into account the avoided emissions from crude oil-based fuel production. We find that overseas production is more economically viable compared to local production, with the best case CCUP bounds giving a range of 142–148 $/tCO2 in 2050 if CO2 transport and fuel shipping costs are low. This is primarily due to the high cost of hydrogen feedstock, especially the transport cost, which can offset the combined costs of CO2 transport and fuel shipping. In general, we find that any increase in the hydrogen feedstock cost can significantly affect the CCUP for local production. Sensitivity analysis reveals that hydrogen transport cost has a significant impact on the viability of local production and if this cost is reduced significantly, local production can be cheaper than overseas production. The same is true if the economies of scale for local production is significantly better than overseas production. A significantly lower carbon capture cost can also the reduce the CCUP significantly.

Climate Policy and Strategic Operations in a Hydro-Thermal Power System

Decarbonisation of the Nordic power sector entails substantial variable renewable energy (VRE) adoption. While Nordic hydropower reservoirs can mitigate VRE output’s intermittency, strategic hydro producers may leverage increased flexibility requirements to exert market power. Using a Nash-Cournot model, we find that even the current Nordic power system could yield modest gains from strategic reservoir operations regardless of a prohibition on “spilling” water to increase prices. Instead, strategic hydro producers could shift generation from peak to offpeak seasons. Such temporal arbitrage becomes more attractive under a climate package with a €100/t CO2 price and doubled VRE capacity. Since the package increases generation variability, lowers average prices, and makes fossil-fuelled plants unprofitable, strategic hydro producers face lower opportunity costs in shifting output from peak to off-peak seasons and encounter muted responses from price-taking fossil-fuelled plants. Hence, a climate package that curtails CO2 emissions may also bolster strategic hydro producers’ leverage.

Heat pump-driven adsorption CO2 capture for simple and cost-effective retrofits of coal power plants

Coal-fired power plants emit almost a third of fossil CO2 emissions worldwide, and continued operation of existing plants will consume the entire remaining CO2 budget for 1.5 °C of global warming. Hence, there is an urgent need to rapidly cut emissions from existing power plants. The continuous swing adsorption reactor (CSAR) concept offers a promising solution to this challenge. CSAR uses electrically powered heat and vacuum pumps to drive the CO2 capture process and does not require the extraction of large amounts of steam from the power plant, greatly simplifying the retrofit process. A bottom-up techno-economic assessment of CSAR compared to conventional temperature swing adsorption (TSA) using the same sorbent showed near-identical performance in terms of energy penalty (8.0 for CSAR and 8.2 %-points for TSA) and CO2 avoidance cost (54.1 €/ton for CSAR and 55.4 €/ton for TSA). Hence, retrofitting simplicity is achieved at no extra cost. The assessment also showed that, although new coal-fired power plants are economically unviable in regions with already high CO2 prices, already depreciated plants will be difficult to displace via market forces. For example, the levelized cost of electricity for a coal power plant retrofitted with CSAR drops from 99.2 €/MWh to 68.2 €/MWh when the power plant is already depreciated. When CO2 prices rise, the optimal strategy involves retrofitting plants located close to CO2 storage or utilization opportunities for continued baseload operation, while unabated plants without easy access to storage are used at lower capacity factors to integrate rising shares of variable renewables. Simplified retrofitting via CSAR can facilitate the practical and economical execution of this strategy, achieving rapid decarbonization while minimizing the need for new capital investments and disruptive early asset retirements.

Can a CO2 Tax Be Socially Just? Analysis of the Social Distribution Effects of the German CO2 Taxation

Rising energy costs have led to increased discussion about the social impact of the energy transition in Germany in recent years. In 2021, a gradually increasing CO2 tax was introduced. This paper analyzes the question of whether a CO2 tax can be socially just. Using data analysis and desk research, correlations between income and energy consumption in Germany are shown. In a short analysis, it is investigated which additional burdens different types of private households have to expect in the coming years due to the introduction of CO2 pricing on energy. In particular, the introduction of a per capita flat rate fed by CO2 tax revenues could be a suitable way to reduce the burden on low-income households.

Techno-economic assessment of a power-to-green methanol plant

Power-to-Liquid plants are a potential linchpin of future energy systems. Economic evaluations are crucial to assess their competitiveness with conventional fossil-based and other innovative processes. A techno-economic assessment of a previously presented plant concept producing green methanol was performed, evaluating different scenarios based on the net present value and annuity method. A hybrid plant was designed to realize an availability comparable to industrial plants. Green methanol prices of 717–1107 €2022/t are required to realize amortization periods between 5 and 25 years. Net production costs of 785 €2022/t were obtained for the base scenario, a surcharge of 44% compared to German methanol prices in 2022. CO2 prices of 220–310 €2022/t are necessary to become cost-competitive with fossil-based methanol. A sensitivity analysis underscored the grid electricity price’s negligible influence on the plant’s economic performance due to the implemented hybrid power plant. Green methanol has the potential to decrease the chemical industry’s carbon footprint while simultaneously substituting fossil imports with local CO2 sources. The presented study provides a concept tackling Power-to-Liquid plants’ major drawbacks by concurrently maximizing annual operating hours and economic performance due to the utilization of renewable electricity. Consequently, stable long-term scenarios for interested investors were established.

Electricity price modeling from the perspective of start-up costs: incorporating renewable resources in non-convex markets

This paper constructs a comprehensive electricity market model in the context of China, highlighting the deviation caused by neglecting start-up costs from an engineering perspective. The model allows for the abandonment of excess wind and solar power generation, contributing to the achievement of research objectives in scenarios with a high proportion of renewable energy. Our method innovatively integrates fuel and carbon prices, clean energy expansion, and power system marginal prices according to the carbon trading rules of the Chinese power industry, providing a more accurate representation of market dynamics. Findings reveal that neglecting start-up costs can lead to significant biases in electricity prices. We demonstrate that the marginal price sometimes deviates from the fluctuation of the real value. While fuel and CO2 prices can be transmitted downstream, the value of new energy must be transmitted through its impact on the marginal unit. This insight is crucial for understanding the “missing money” problem in electricity markets. Based on these findings, we propose policy recommendations. We suggest considering fixed and average costs as pricing benchmarks and utilizing capacity utilization as a signal for demand response to adjust power pricing. Furthermore, we recommend trading different energy types separately in the spot market with different pricing benchmarks to ensure the homogeneity of marginal units.

Evaluation of sector-coupled energy systems using different foresight horizons

Energy system models are increasingly being used in politics, industry and science. At the same time, model complexity continues to increase. Different possibilities of computing time reduction are in use, for example rolling horizons and incremental optimisation with reduced foresight. However, the combination of using strongly sector-coupled models with different foresight variants, in particular, has not been investigated thoroughly yet. This study aims to evaluate different model foresights by using a mathematical model of the German energy system, which includes electricity and heat supply as well as the supply of basic chemicals and mobility. Three scenarios of this model are used to evaluate the influences of changing foresights. The considered foresight variants are perfect foresight, myopia incremental, and myopia with foresight. Carbon budget models are shown to be more suitable than the price drop and CO2 price variants with the aim to minimise deviations from the least-cost energy system transformation. Moreover, this study demonstrates the importance of the chosen model foresight. If the goal of the optimisation is to simulate unforeseen events or shocks, the foresight of the model should be chosen to have a rather small value to depict a realistic reaction of the model. If the goal is rather to simulate long-lasting consequences of decisions taken at the beginning of the simulation, the foresight horizons should be chosen to be rather long while also considering the computational costs that scale with increasing foresight.

From excavated waste to hydrogen: Life cycle techno-environmental-economic comparison between plasma-gasification-based water gas shift and sorption enhanced water gas shift routes

The mismanagement of excavated waste (EW) is leading to serious land occupancy and greenhouse gases leakage problems globally. This study explores the possibility to realize utilization of EW and satisfaction of the hydrogen fuel demand at the same time. Based on plasma gasification (PG), the excavated waste has shown its potential to act as a sustainable source of hydrogen. In this study, the techno-environmental-economic performance of the EWtH (excavated waste to hydrogen) process based on PG-WGS-AGR (water gas shift-acid gas removal) and PG-SEWGS (sorption enhanced water gas shift) routes are investigated. The results demonstrate that the EWtH process based on the PG-SEWGS route has higher exergy efficiency, better environmental performance, and more promising economic feasibility. The EWtH process can maintain profitable when resisting the fluctuation of EW treatment subsidy, selling price of CO2 and carbon tax (±75%), with the biggest LPEW (levelized profit of excavated waste) drop of 19.22%. However, as the selling of H2 is the largest income, the LPEW has decreased to a negative value within the fluctuation of the selling price of H2 in ± 55%, which suggests that the selling price of H2 is the decisive factor in the economic feasibility of the EWtH process. Also, the EW with fewer landfill years brings higher profit, and the material recovery process plays a more significant role in the treatment of EW with longer landfill years. The highest exergy efficiency (57.79%) and the most environmentally friendly performance (-70.84 mPE) locates in the 05-EWtH process applying SEWGS, and the 15-EWtH process based on PG-SEWGS route has the highest LPEW of 185.78 $/tonEW.

Impact of large-scale Bio-CCS deployment on forest biomass competition and forest industry production

This study investigates the implications of large-scale Bio-CCS deployment on forest-based biofuel, kraft pulp, and district heating production, focusing on the resulting biomass competition. Using the Nordic Forest Sector Model (NFSM) with a Bio-CCS add-on, we integrate negative emission trading into the EU Emissions Trading System across a range of CO2 price levels. The findings reveal that biofuel production increases with higher carbon dioxide prices, with different technologies demonstrating profitability at different price points. As CO2 prices rise, the competition for high-quality biomass intensifies between the biofuel and kraft pulp sectors, while district-heating biomass boilers serve as important buffers. Notably, The deployment of Bio-CCS in kraft pulp mills and biofuel plants significantly raises the demand for pulpwood, while district heating remains unaffected. As a result, district heating systems consume more forest residues and industrial residues. Consequently, increased use of Bio-CCS results in higher pulpwood and sawdust prices. The extreme test with a carbon price of 300€/tCO2 reveals a higher risk of carbon sequestration leakage, while the increased harvest levels in the studied areas remain sustainable. This modeling approach and its main conclusions offer valuable insights for other forest-based economies.

Short-term modeling of carbon price based on fuel and energy determinants in EU ETS

Accurate price forecasts on the European Union Emissions Trading System (EU ETS) market are of interest to many production and investment entities. The article presents a new approach, which models the most significant determinants by the use of a rule-based model containing facts written in the form of ordered fuzzy numbers, as the description of trends of imprecise values of prices. This approach allows for a qualitative analysis of potential values and directions of EU allowance (EUA) price changes and their trends along with the probability of their occurrence in the future. Article presents a wide set of factors used for the analysis of EUA price conditions and the comparison of the results of various feature selection methods (Hellwig's method, F-test, Neighborhood Component Feature Selection method, RreliefF method). Another scientific value added to the presented research results is a new approach to modeling an influence of the significant determinants for a day-ahead prediction CO2 price in the form of fuzzy rules which contain additional information about the tendencies of value changes. Thanks to a comprehensive approach, improvements to existing methods, and proprietary models, additional information was obtained about the tendencies of EUA price level changes.

Risk aversion and flexibility options in electricity markets

Flexibility options, such as demand response, energy storage and interconnection, have the potential to reduce variation in electricity prices between different future scenarios, thereby reducing investment risk. Investing in flexibility options can also lower the need for generation capacity. However, there are complex interactions between different flexibility options. In this paper, we investigate the interactions between flexibility and investment risk in electricity markets. In particular, we focus on the investment strategies of risk-averse decision-makers. We employ a large-scale stochastic transmission and generation expansion model of the European electricity system, providing it with uncertain future scenarios based on ENTSOs’ Ten-Year Network Development Plan. Using this model, we first investigate the effect of risk aversion on investment decisions. We find that the interplay of parameters leads to (i) more investment in a less emission-intensive energy system if planners are risk averse (hedging against CO2 price uncertainty), (ii) constant total installed capacity, regardless of the level of risk aversion (i.e. planners do not hedge against demand and uncertainties when deploying renewable energy sources) and (iii) an allocation of investments that disregards cost differences for load shedding across Europe. Second, we examine the individual effects of three flexibility elements on optimal investment levels at different levels of risk aversion: demand response, investment in additional interconnection capacity and investment in additional energy storage. We show that flexible technologies have a higher value for risk-averse decision-makers, although the effects are nonlinear. Finally, we investigate the interactions between the flexibility elements. We find that risk-averse decision-makers show a strong preference for transmission-grid expansion once flexibility is available at a low cost.

Simulation-based quantitative methods for vehicle emissions and a CO2 charging policy

With the worsening vehicle emissions, carbon emission charges are becoming an increasingly popular policy to reduce emissions. This paper proposes a policy to charge for the additional CO2 emissions due to the increasing traffic flow for each vehicle, thereby extending traditional travel time-based traffic assignment to emissions-charged traffic assignment. Considering that vehicle movements in the network are affected by signal timings and the car-following together with lanechanging interactions of different types of vehicles, microscopic traffic flow simulation is combined with a CO2 emission model to formulate the relations between link flow and emissions of different types of vehicles. Accordingly, the additional CO2 emissions due to increasing traffic flow are quantified and charged for each vehicle, leading to multi-vehicle-type and multi-criteria traffic assignment. Through an example network, the proposed flow-emissions model is verified and the impacts of different CO2 charging prices in the morning peak hour are investigated. Analysis of the results shows monotone increasing relations between price and reduced total emissions as well as increased revenue within the price range. In addition, the charging policy also leads to traffic assignment that achieves a system-optimal assignment since the CO2 pricing aligns with the general concept of pricing externality, thereby reducing the total travel time.

Are green and blue hydrogen competitive or complementary? Insights from a decarbonized European power system analysis

Hydrogen will be important in decarbonized energy systems. The primary ways to produce low emission hydrogen are from renewable electricity using electrolyzers, called green hydrogen, and by reforming natural gas and capturing and storing the CO2, known as blue hydrogen. In this study, the degrees to which blue and green hydrogen are complementary or competitive are analyzed through a sensitivity analysis on the electrolyzer costs, and natural gas price. This analysis is performed on four bases: what is the cost-effective relative share between blue and green hydrogen deployment, how their deployment influences the price of hydrogen, how the price of CO2 changes with the deployment of these two technologies, and whether infrastructure can economically be shared between these two technologies. The results show that the choice of green and blue hydrogen has a tremendous impact, where an early deployment of green leads to higher hydrogen costs and CO2 prices in 2030. Allowing for blue hydrogen thus has notable benefits in 2030, giving cheaper hydrogen with smaller wider socioeconomic impacts. In the long term, these competitive aspects disappear, and green and blue hydrogen can coexist in the European market without negatively influencing one another.

Deep decarbonisation pathways of the energy system in times of unprecedented uncertainty in the energy sector

Unprecedented investments in clean energy technology are required for a net-zero carbon energy system before temperatures breach the Paris Agreement goals. By performing a Monte-Carlo Analysis with the detailed ETSAP-TIAM Integrated Assessment Model and by generating 4000 scenarios of the world's energy system, climate and economy, we find that the uncertainty surrounding technology costs, resource potentials, climate sensitivity and the level of decoupling between energy demands and economic growth influence the efficiency of climate policies and accentuate investment risks in clean energy technologies. Contrary to other studies relying on exploring the uncertainty space via model intercomparison, we find that the CO2 emissions and CO2 prices vary convexly and nonlinearly with the discount rate and climate sensitivity over time. Accounting for this uncertainty is important for designing climate policies and carbon prices to accelerate the transition. In 70% of the scenarios, a 1.5 °C temperature overshoot was within this decade, calling for immediate policy action. Delaying this action by ten years may result in 2 °C mitigation costs being similar to those required to reach the 1.5 °C target if started today, with an immediate peak in emissions, a larger uncertainty in the medium-term horizon and a higher effort for net-zero emissions.

Integration of power-to-gas into electricity markets during the ramp-up phase—Assessing the role of carbon pricing

The expansion of wind and solar energy has so far primarily led to the decarbonization of the electricity sector. Against this background, power-to-gas (PtG) is seen as a solution supporting the decarbonization of other sectors, such as heating or transport. As the generation mix will transitionally be based on fossil-fired generation technologies, the upcoming integration of PtG into electricity markets comes with several challenges. While the current debate focuses on sustainability criteria and support mechanisms, integration of PtG into electricity markets requires a further development of the market design. Notably, the design of electricity markets and carbon pricing should create efficient incentives for utilizing PtG, reflecting the value of the CO2 emissions avoided by electrolytic hydrogen or methane. General effects are analyzed to study the role of carbon pricing in integrating PtG. Moreover, a detailed bottom-up market model is extended by the PtG technology and competing flexibilities, such as storage or demand-side management. Several scenarios are developed regarding levels of CO2 price, techno-economic parameters of flexibilities and shares of variable renewable energy sources for 2025. The results reveal that carbon pricing has to reflect both the avoided and the induced CO2 emissions related to electrolytic hydrogen or methane to support the market integration of PtG during the ramp-up phase. On the contrary, too low CO2 prices might lead to adverse effects. Subsequently, implications for energy policy are discussed.

Ammonia from solid fuels: A cost-effective route to energy security with negative CO2 emissions

This study investigates a potential solution to the global challenge of secure, affordable, and low-carbon energy supply: ammonia production from local coal and biomass resources with CO2 capture for negative emissions. Two innovative configurations; an E-gas gasifier with membrane-assisted water-gas shift and an air-blown MHI gasifier design, are compared with an oxygen-blown GE gasifier benchmark. Under the baseline cost assumptions of 2.5 €/GJ for coal, 6.1 €/GJ for biomass, and a CO2 tax of 100 €/ton, the GE configuration reached a levelized cost of ammonia (LCOA) of 391.5 €/ton, while the E-gas and MHI concepts showed 59.0 (−15.1%) and 18.6 (4.8%) €/ton lower and higher costs, respectively. Subsequent benchmarking against alternative ammonia supply pathways showed that the energy security offered by the E-gas configuration comes at a premium of around 40% over ammonia imported at cost from natural gas exporting regions, which will be cheaper than liquified natural gas if the CO2 price exceeds 60.9 €/ton. Since prices of imported energy are generally well above the cost of production, the carbon-negative energy security offered by the proposed plants can be economically attractive to importers with rising CO2 taxes. Thus, policy support for establishing local ammonia value chains can be recommended.

Tropical mixed-species plantations can outperform monocultures in terms of carbon sequestration and economic return

Tropical reforestation is an important strategy to mitigate the global climate crisis through the sequestration of CO2. Together with increasing CO2 prices, carbon storage becomes increasingly relevant for commercial reforestations. Due to higher productivity, mixed-species reforestations have been suggested for carbon plantings. Yet, current studies comparing mixtures and monocultures lack an in-depth comparison of economic and carbon sequestration potentials. Moreover, their economic valuations do not consider carbon payments and differences in forest management. Using a simulation-optimization approach, we compared the economic and carbon sequestration performance of commercial mixed-species stands and monocultures in Costa Rica. Mixed-species stands outperformed their monoculture peers by net present value (NPV) up to 3135 USD/ha if only timber sales were considered, or 3500–16,800 USD/ha if carbon payments were also considered (at a discount rate of 8%). When managed solely for carbon sequestration, the best-performing mixture achieved a mean stand carbon 7% above the best-performing monoculture. The results were sensitive to the comparison baseline applied. The results of this study suggest that tropical mixed-species plantations can be a competitive alternative to monocultures. Forest investors could benefit from establishing mixed-species plantations when reforesting plantation sites where species-specific site suitability is uncertain, or when working with lesser-studied tree species.

Estimating the CO2 marginal abatement cost and implications for climate policies in China’s industrial sector: A firm-level analysis

ABSTRACT This paper presents an in-depth analysis of the Marginal Abatement Cost Curve (MACC) for CO2 of China’s industrial sector. Leveraging comprehensive firm-level panel data spanning the period 2011–2015, we employ a parameterized directional output distance function to estimate the shadow price of CO2. By doing so, we derive the marginal abatement cost for individual firms across different years, which provides crucial insights into two fundamental aspects: first, the variation in shadow prices as indicators of the economic efficiency of existing climate policies; and second, the carbon price levels necessary to achieve CO2 mitigation targets in the future. Furthermore, we conduct scenario simulations to assess the potential industrial output loss resulting from forthcoming carbon policies, such as the European Union’s Carbon Border Adjustment Mechanism (CBAM). Our findings underscore the necessity for a considerably higher tax rate to stimulate pollution reduction in order to meet the desired emission targets.

Exploring risks and benefits of overshooting a 1.5 °C carbon budget over space and time

Temperature targets of the Paris Agreement limit global net cumulative emissions to very tight carbon budgets. The possibility to overshoot the budget and offset near-term excess emissions by net-negative emissions is considered economically attractive as it eases near-term mitigation pressure. While potential side effects of carbon removal deployment are discussed extensively, the additional climate risks and the impacts and damages have attracted less attention. We link six models for an integrative analysis of the climatic, environmental and socio-economic consequences of temporarily overshooting a carbon budget consistent with the 1.5 °C temperature target along the cause-effect chain from emissions and carbon removals to climate risks and impact. Global climatic indicators such as CO2-concentration and mean temperature closely follow the carbon budget overshoot with mid-century peaks of 50 ppmv and 0.35 °C, respectively. Our findings highlight that investigating overshoot scenarios requires temporally and spatially differentiated analysis of climate, environmental and socioeconomic systems. We find persistent and spatially heterogeneous differences in the distribution of carbon across various pools, ocean heat content, sea-level rise as well as economic damages. Moreover, we find that key impacts, including degradation of marine ecosystem, heat wave exposure and economic damages, are more severe in equatorial areas than in higher latitudes, although absolute temperature changes being stronger in higher latitudes. The detrimental effects of a 1.5 °C warming and the additional effects due to overshoots are strongest in non-OECD countries (Organization for Economic Cooperation and Development). Constraining the overshoot inflates CO2 prices, thus shifting carbon removal towards early afforestation while reducing the total cumulative deployment only slightly, while mitigation costs increase sharply in developing countries. Thus, scenarios with carbon budget overshoots can reverse global mean temperature increase but imply more persistent and geographically heterogeneous impacts. Overall, the decision about overshooting implies more severe trade-offs between mitigation and impacts in developing countries.

Can Hydrogen Production Be Economically Viable on the Existing Gas-Fired Power Plant Location? New Empirical Evidence

The paper provides an economic model for the assessment of hydrogen production at the site of an existing thermal power plant, which is then integrated into the existing gas grid. The model uses projections of electricity prices, natural gas prices, and CO2 prices, as well as estimates of the cost of building a power-to-gas system for a 25-year period. The objective of this research is to calculate the yellow hydrogen production price for each lifetime year of the Power-to-gas system to evaluate yellow hydrogen competitiveness compared to the fossil alternatives. We test if an incentive scheme is needed to make this technology economically viable. The research also provides several sensitivity scenarios of electricity, natural gas, and CO2 price changes. Our research results clearly prove that yellow hydrogen is not yet competitive with fossil alternatives and needs incentive mechanisms for the time being. At given natural gas and CO2 prices, the incentive for hydrogen production needs to be 52.90 EUR/MWh in 2025 and 36.18 EUR/MWh in 2050. However, the role of hydrogen in the green transition could be very important as it provides ancillary services and balances energy sources in the power system.