Baseload wind energy: modeling the competition between gas turbines and compressed air energy storage for supplemental generation

The economic viability of producing baseload wind energy was explored using a cost-optimization model to simulate two competing systems: wind energy supplemented by simple- and combined cycle natural gas turbines (“wind+gas”), and wind energy supplemented by compressed air energy storage (“wind+CAES”). Pure combined cycle natural gas turbines (“gas”) were used as a proxy for conventional baseload generation. Long-distance electric transmission was integral to the analysis. Given the future uncertainty in both natural gas price and greenhouse gas (GHG) emissions price, we introduced an effective fuel price, p_NGeff, being the sum of the real natural gas price and the GHG price. Under the assumption of p_NGeff=$5/GJ (lower heating value), 650 W/m² wind resource, 750 km transmission line, and a fixed 90% capacity factor, wind+CAES was the most expensive system at ¢6.0/kWh, and did not break even with the next most expensive wind+gas system until p_NGeff=$9.0/GJ. However, under real market conditions, the system with the least dispatch cost (short-run marginal cost) is dispatched first, attaining the highest capacity factor and diminishing the capacity factors of competitors, raising their total cost. We estimate that the wind+CAES system, with a greenhouse gas (GHG) emission rate that is one-fourth of that for natural gas combined cycle plants and about one-tenth of that for pulverized coal plants, has the lowest dispatch cost of the alternatives considered (lower even than for coal power plants) above a GHG emissions price of $35/tC_equiv., with good prospects for realizing a higher capacity factor and a lower total cost of energy than all the competing technologies over a wide range of effective fuel costs. This ability to compete in economic dispatch greatly boosts the market penetration potential of wind energy and suggests a substantial growth opportunity for natural gas in providing baseload power via wind+CAES, even at high natural gas prices.     

Economics of compressed air energy storage to integrate wind power: A case study in ERCOT

Compressed air energy storage (CAES) could be paired with a wind farm to provide firm, dispatchable baseload power, or serve as a peaking plant and capture upswings in electricity prices. We present a firm-level engineering-economic analysis of a wind/CAES system with a wind farm in central Texas, load in either Dallas or Houston, and a CAES plant whose location is profit-optimized. With 2008 hourly prices and load in Houston, the economically optimal CAES expander capacity is unrealistically large – 24 GW – and dispatches for only a few hours per week when prices are highest; a price cap and capacity payment likewise results in a large (17 GW) profit-maximizing CAES expander. Under all other scenarios considered the CAES plant is unprofitable. Using 2008 data, a baseload wind/CAES system is less profitable than a natural gas combined cycle (NGCC) plant at carbon prices less than $56/tCO₂ ($15/MMBTU gas) to $230/tCO₂ ($5/MMBTU gas). Entering regulation markets raises profit only slightly. Social benefits of CAES paired with wind include avoided construction of new generation capacity, improved air quality during peak times, and increased economic surplus, but may not outweigh the private cost of the CAES system nor justify a subsidy.     

Improving the technical, environmental and social performance of wind energy systems using biomass-based energy storage

A completely renewable baseload electricity generation system is proposed by combining wind energy, compressed air energy storage, and biomass gasification. This system can eliminate problems associated with wind intermittency and provide a source of electrical energy functionally equivalent to a large fossil or nuclear power plant. Compressed air energy storage (CAES) can be economically deployed in the Midwestern US, an area with significant low-cost wind resources. CAES systems require a combustible fuel, typically natural gas, which results in fuel price risk and greenhouse gas emissions. Replacing natural gas with synfuel derived from biomass gasification eliminates the use of fossil fuels, virtually eliminating net CO₂ emissions from the system. In addition, by deriving energy completely from farm sources, this type of system may reduce some opposition to long distance transmission lines in rural areas, which may be an obstacle to large-scale wind deployment.     

Cost and performance of fossil fuel power plants with CO2 capture and storage

CO₂ capture and storage (CCS) is receiving considerable attention as a potential greenhouse gas (GHG) mitigation option for fossil fuel power plants. Cost and performance estimates for CCS are critical factors in energy and policy analysis. CCS cost studies necessarily employ a host of technical and economic assumptions that can dramatically affect results. Thus, particular studies often are of limited value to analysts, researchers, and industry personnel seeking results for alternative cases. In this paper, we use a generalized modeling tool to estimate and compare the emissions, efficiency, resource requirements and current costs of fossil fuel power plants with CCS on a systematic basis. This plant-level analysis explores a broader range of key assumptions than found in recent studies we reviewed for three major plant types: pulverized coal (PC) plants, natural gas combined cycle (NGCC) plants, and integrated gasification combined cycle (IGCC) systems using coal. In particular, we examine the effects of recent increases in capital costs and natural gas prices, as well as effects of differential plant utilization rates, IGCC financing and operating assumptions, variations in plant size, and differences in fuel quality, including bituminous, sub-bituminous and lignite coals. Our results show higher power plant and CCS costs than prior studies as a consequence of recent escalations in capital and operating costs. The broader range of cases also reveals differences not previously reported in the relative costs of PC, NGCC and IGCC plants with and without CCS. While CCS can significantly reduce power plant emissions of CO₂ (typically by 85–90%), the impacts of CCS energy requirements on plant-level resource requirements and multi-media environmental emissions also are found to be significant, with increases of approximately 15–30% for current CCS systems. To characterize such impacts, an alternative definition of the “energy penalty” is proposed in lieu of the prevailing use of this term.     

A comparison of electricity and hydrogen production systems with CO2 capture and storage. Part A: Review and selection of promising conversion and capture technologies

We performed a consistent comparison of state-of-the-art and advanced electricity and hydrogen production technologies with CO₂ capture using coal and natural gas, inspired by the large number of studies, of which the results can in fact not be compared due to specific assumptions made. After literature review, a standardisation and selection exercise has been performed to get figures on conversion efficiency, energy production costs and CO₂ avoidance costs of different technologies, the main parameters for comparison. On the short term, electricity can be produced with 85–90% CO₂ capture by means of NGCC and PC with chemical absorption and IGCC with physical absorption at 4.7–6.9 €ct/kWh, assuming a coal and natural gas price of 1.7 and 4.7 €/GJ. CO₂ avoidance costs are between 15 and 50 €/t CO₂ for IGCC and NGCC, respectively. On the longer term, both improvements in existing conversion and capture technologies are foreseen as well as new power cycles integrating advanced turbines, fuel cells and novel (high-temperature) separation technologies. Electricity production costs might be reduced to 4.5–5.3 €ct/kWh with advanced technologies. However, no clear ranking can be made due to large uncertainties pertaining to investment and O&M costs. Hydrogen production is more attractive for low-cost CO₂ capture than electricity production. Costs of large-scale hydrogen production by means of steam methane reforming and coal gasification with CO₂ capture from the shifted syngas are estimated at 9.5 and 7 €/GJ, respectively. Advanced autothermal reforming and coal gasification deploying ion transport membranes might further reduce production costs to 8.1 and 6.4 €/GJ. Membrane reformers enable small-scale hydrogen production at nearly 17 €/GJ with relatively low-cost CO₂ capture.     

The long-term life cycle private and external costs of high coal usage in the US

Using four times as much coal in 2050 for electricity production need not degrade air quality or increase greenhouse gas emissions. Current SO_x and NO_x emissions from the power sector could be reduced from 12 to less than 1 and from 5 to 2 million tons annually, respectively, using advanced technology. While direct CO₂ emissions from new power plants could be reduced by over 87%, life cycle emissions could increase by over 25% due to the additional coal that is required to be mined and transported to compensate for the energy penalty of the carbon capture and storage technology. Strict environmental controls push capital costs of pulverized coal (PC) and integrated coal gasification combined cycle (IGCC) plants to $1500–1700/kW and $1600–2000/kW, respectively. Adding carbon capture and storage (CCS) increases costs to $2400–2700/kW and $2100–3000/kW (2005 dollars), respectively. Adding CCS reduces the 40–43% efficiency of the ultra-supercritical PC plant to 31–34%; adding CCS reduces the 32–38% efficiency of the GE IGCC plant to 27–33%. For IGCC, PC, and natural gas combined cycle (NGCC) plants, the carbon dioxide tax would have to be $53, $74, and $61, respectively, to make electricity from a plant with CCS cheaper. Capturing and storing 90% of the CO₂ emissions increases life cycle costs from 5.4 to 11.6 cents/kWh. This analysis shows that 90% CCS removal efficiency, although being a large improvement over current electricity generation emissions, results in life cycle emissions that are large enough that additional effort is required to achieve significant economy-wide reductions in the US for this large increase in electricity generation using either coal or natural gas.     

Life cycle GHG assessment of fossil fuel power plants with carbon capture and storage

The evaluation of life cycle greenhouse gas emissions from power generation with carbon capture and storage (CCS) is a critical factor in energy and policy analysis. The current paper examines life cycle emissions from three types of fossil-fuel-based power plants, namely supercritical pulverized coal (super-PC), natural gas combined cycle (NGCC) and integrated gasification combined cycle (IGCC), with and without CCS. Results show that, for a 90% CO₂ capture efficiency, life cycle GHG emissions are reduced by 75–84% depending on what technology is used. With GHG emissions less than 170 g/kWh, IGCC technology is found to be favorable to NGCC with CCS. Sensitivity analysis reveals that, for coal power plants, varying the CO₂ capture efficiency and the coal transport distance has a more pronounced effect on life cycle GHG emissions than changing the length of CO₂ transport pipeline. Finally, it is concluded from the current study that while the global warming potential is reduced when MEA-based CO₂ capture is employed, the increase in other air pollutants such as NO_x and NH₃ leads to higher eutrophication and acidification potentials.     

Determinants of the costs of carbon capture and sequestration for expanding electricity generation capacity

This study models the costs of electricity generation with carbon capture and sequestration (CCS), from generation at the power plant to carbon injection at the reservoir, examining the economic factors that affect technology choice and CCS costs at the individual plant level. The results suggest that natural gas and coal prices have profound impacts on the carbon price needed to induce CCS. To extend previous analyses we develop a "cost region" graph that models technology choice as a function of carbon and fuel prices. Generally, the least-cost technology at low carbon prices is pulverized coal, while intermediate carbon prices favor natural gas technologies and high carbon prices favor coal gasification with capture. However, the specific carbon prices at which these transitions occur is largely determined by the price of natural gas. For instance, the CCS-justifying carbon price ranges from $27/t CO₂ at high natural gas prices to $54/t CO₂ at low natural gas prices. This result has important implications for potential climate change legislation. The capital costs of the generation and CO₂ capture plant are also highly important, while pipeline distance and criteria pollutant control are less significant.     

Optimal greenhouse gas emissions in NGCC plants integrating life cycle assessment

The optimal design of an energy-intensive process involves a compromise between costs and greenhouse gas emissions, complicated by the interaction between optimal process emissions and supply chain emissions. We propose a method that combines generic abatement cost estimates and the results of existing (LCA) life cycle assessment studies, so that supply chain emissions are properly handled during optimization. This method is illustrated for a (NGCC) natural gas combined cycle power plant model with the following design and procurement options: procurement of natural gas from low-emissions producers, fuel substitution with (SNG) synthetic natural gas from wood, and variable-rate CO₂ capture and sequestration from both the NGCC and SNG plants. Using multi-objective optimization, we show two Pareto-optimal sets with and without the proposed LCA method. The latter can then be shown to misestimate CO₂ abatement costs by a few percent, penalizing alternate fuels and energy-efficient process configurations and leading to sub-optimal design decisions with potential net losses of the order of $1/MWh. Thus, the proposed LCA method can enhance the economic analysis of emissions abatement technologies and emissions legislation in general.     

Internalizing externalities of electricity generation: An analysis with MESSAGE-MACRO

This paper examines the global impacts of a policy that internalizes the external costs (related to air pollution damage, excluding climate costs) of electricity generation using a combined energy systems and macroeconomic model. Starting point are estimates of the monetary damage costs for SO₂, NO_X, and PM per kWh electricity generated, taking into account the fuel type, sulfur content, removal technology, generation efficiency, and population density. Internalizing these externalities implies that clean and advanced technologies increase their share in global electricity production. Particularly, advanced coal power plants, natural gas combined cycles, natural gas fuel cells, wind and biomass technologies gain significant market shares at the expense of traditional coal- and gas-fired plants. Global carbon dioxide emissions are lowered by 3% to 5%. Sulfur dioxide emissions drop significantly below the already low level. The policy increases the costs of electricity production by 0.2 (in 2050) to 1.2 € cent/kWh (in 2010). Gross domestic product losses are between 0.6% and 1.1%. They are comparatively high during the initial phase of the policy, pointing to the need for a gradual phasing of the policy.     

Trade-off in emissions of acid gas pollutants and of carbon dioxide in fossil fuel power plants with carbon capture

This paper investigates the impact of capture of carbon dioxide (CO₂) from fossil fuel power plants on the emissions of nitrogen oxides (NO_X) and sulphur oxides (SO_X), which are acid gas pollutants. This was done by estimating the emissions of these chemical compounds from natural gas combined cycle and pulverized coal plants, equipped with post-combustion carbon capture technology for the removal of CO₂ from their flue gases, and comparing them with the emissions of similar plants without CO₂ capture. The capture of CO₂ is not likely to increase the emissions of acid gas pollutants from individual power plants; on the contrary, some NO_X and SO_X will also be removed during the capture of CO₂. The large-scale implementation of carbon capture is however likely to increase the emission levels of NO_X from the power sector due to the reduced efficiency of power plants equipped with capture technologies. Furthermore, SO_X emissions from coal plants should be decreased to avoid significant losses of the chemicals that are used to capture CO₂. The increase in the quantity of NO_X emissions will be however low, estimated at 5% for the natural gas power plant park and 24% for the coal plants, while the emissions of SO_X from coal fired plants will be reduced by as much as 99% when at least 80% of the CO₂ generated will be captured.     

Transitioning electricity systems: The environmental benefits and economic cost of repurposing surplus electricity in non-conventional end users

A power grid with a lower global warming impact has the potential to extend its benefits to energy systems that conventionally do not utilize electricity as their primary energy source. This study presents the case of Ontario where the role of complementing policies in transitioning electricity systems is assessed. The policy cost to incentivize surplus low emission electricity via an established mechanism for the transportation sector has been estimated (Electric and Hydrogen Vehicle Incentive Program). It is estimated that the 9056 (4760 battery and 4296 plug-in hybrid) electric vehicles that qualified for incentives from the provincial government at the end of 2016 vehicles cost $732.5-$883.9 to reduce a tonne of CO_2,e emissions over an eight year lifetime. This is then compared with the potential cost incurred by two power to gas energy hubs that utilize clean surplus electricity from the province to offset emissions within the natural gas sector. The use of hydrogen-enriched natural gas and synthetic natural gas (SNG) offsets emissions at $87.8 and $228.7 per tonne of CO_2,e in the natural gas sector. This analysis highlights the potential future costs for incentivizing new clean technologies such as electric vehicles and power to gas energy hubs in jurisdictions with a transitioning electricity system.     

Techno‐economic study of compressed air energy storage systems for the grid integration of wind power

Integrating variable renewable energy from wind farms into power grids presents challenges for system operation, control, and stability due to the intermittent nature of wind power. One of the most promising solutions is the use of compressed air energy storage (CAES). The main purpose of this paper is to examine the technical and economic potential for use of CAES systems in the grid integration. To carry out this study, 2 CAES plant configurations: adiabatic CAES (A‐CAES) and diabatic CAES (D‐CAES) were modelled and simulated by using the process simulation software ECLIPSE. The nominal compression and power generation of both systems were given at 100 and 140 MWe, respectively. Technical results showed that the overall energy efficiency of the A‐CAES was 65.6%, considerably better than that of the D‐CAES at 54.2%. However, it could be seen in the economic analysis that the breakeven electricity selling price (BESP) of the A‐CAES system was much higher than that of the D‐CAES system at €144/MWh and €91/MWh, respectively. In order to compete with large‐scale fossil fuel power plants, we found that a CO₂ taxation scheme (with an assumed CO₂‐tax of €20/tonne) improved the economic performance of both CAES systems significantly. This advantage is maximised if the CAES systems use low carbon electricity during its compression cycle, either through access to special tariffs at times of low carbon intensity on the grid, or by direct coupling to a clean energy source, for example a 100‐MW class wind farm.     

Opportunities for integration of biofuel gasifiers in natural-gas combined heat-and-power plants in district-heating systems

As political pressure to improve efficiency and reduce CO₂-emissions increases, natural gas combined cycle (NGCC) combined heat-and-power (CHP) technology is an increasingly attractive option for district-heating systems. However, as CO₂-emissions reduction targets become more ambitious, it is expected that there will be pressure to reduce CO₂-emissions from such units well before they reach the end of their useful lifetime. One way to achieve this goal is to integrate a biofuel gasification unit at the plant site. After clean-up, the produced syngas can be co-fired in the CHP unit. This paper discusses the economic performance of this type of retrofit, with specific emphasis on the impact of the following parameters: (i) the original NGCC CHP plant’s power-to-heat ratio; (ii) the size of the district-heating system’s annual heat-energy demand; (iii) the fuel mix in the district-heating system; and (iv) the availability of low-cost waste-heat that can be delivered to the district-heating system. The economic performance of the retrofitted CHP unit is measured as the overall cost of electricity production (COE). COE is analysed for four different energy-market parameter sets (referred to as Scenarios), including fuel prices, costs associated with energy and climate change policy instruments, and market electricity prices. The results indicate that even relatively high costs associated with CO₂ emissions are insufficient to motivate retrofitting an NGCC CHP unit with an integrated biofuel-gasification unit. To promote this type of retrofit, an additional premium value for electricity generated from renewable fuel sources is required (such as the Swedish REC renewable energy certificate system). An unexpected result of this study is that the required value of REC is essentially independent of the energy market scenario considered.     

CO2 mitigation costs for new renewable energy capacity in the Mexican electricity sector using renewable energies

Carbon dioxide mitigation costs for the Mexican power sector are calculated in order to compare the business as usual (BAU) scenario, based on natural gas capacity growth, to a transition scenario where electricity generation growth using natural gas after 2007 is replaced by renewable energies (solar, wind, hydro and biomass). The mitigation costs are obtained using the following parameters: natural gas price, discount rate and technological progress. The latter is expressed in terms of the anticipated decrease in capital costs, as reported in electricity generation technological literature. Our results show that when technological progress is considered, CO₂ mitigation costs decrease rapidly from 14 $/tCO₂ (in this paper $ express 1997 US dollars and t means metric tons) to zero when the price of natural gas nears 2.68 $/GJ, (for some readers, it can be useful to know that 1.0 US$1997/GJ is 1.19 US$2001/MMBTU) which is almost the same as the 2002 price. This means that for middle natural gas prices a “no regrets” situation can be achieved. Our results also show that for prices higher than 2.80 $/GJ, the incorporation of the technological progress parameter transforms the transition scenario into a “no regrets” scenario for all the discount rate values considered in this study.     

Comparing least cost scenarios for 100% renewable electricity with low emission fossil fuel scenarios in the Australian National Electricity Market

Policy makers face difficult choices in planning to decarbonise their electricity industries in the face of significant technology and economic uncertainties. To this end we compare the projected costs in 2030 of one medium-carbon and two low-carbon fossil fuel scenarios for the Australian National Electricity Market (NEM) against the costs of a previously published scenario for 100% renewable electricity in 2030. The three new fossil fuel scenarios, based on the least cost mix of baseload and peak load power stations in 2010, are: (i) a medium-carbon scenario utilising only gas-fired combined cycle gas turbines (CCGTs) and open cycle gas turbines (OCGTs); (ii) coal with carbon capture and storage (CCS) plus peak load OCGT; and (iii) gas-fired CCGT with CCS plus peak load OCGT. We perform sensitivity analyses of the results to future carbon prices, gas prices, and CO₂ transportation and storage costs which appear likely to be high in most of Australia. We find that only under a few, and seemingly unlikely, combinations of costs can any of the fossil fuel scenarios compete economically with 100% renewable electricity in a carbon constrained world. Our findings suggest that policies pursuing very high penetrations of renewable electricity based on commercially available technology offer a cost effective and low risk way to dramatically cut emissions in the electricity sector.     

Process simulation and integration of IGCC systems for H2/syngas/electricity generation with control on CO2 emissions

IGCC is a pre-combustion technology that can be effectively used to produce both hydrogen and electricity while reducing the greenhouse gas (GHG) emissions. Two process models are developed in Aspen Plus^® software and are compared techno-economically. The conventional design of IGCC process is taken as case 1, whereas, case 2 represents the conceptual design of sequential integration of reforming model with the gasification unit to enhance the syngas yield. The case 2 utilizes the steam generated in the gasification process to sustain the methane reforming process which consequently enhances both the H₂ production capacity and cold gas efficiency. It has been analyzed from results that case 2 can enhance the process performance by 4.77% and economics in terms of cost of electricity by 5.9% compared to the conventional process. However, the utilization of natural gas in the case 2 is considered as a standalone fuel so the process performance of NGCC power plants has been also incorporated to ensure the realistic analysis. The results also showed that case 2 design offers 3.9% higher process performance than the cumulative (IGCC + NGCC) processes, respectively. Moreover, the CO₂ specific emissions and LCOE for the case 2 is also lower than the case.     

Valuing flexibility: The case of an Integrated Gasification Combined Cycle power plant

In this paper we analyze the choice between two technologies for producing electricity. In particular, the firm has to decide whether and when to invest either in a Natural Gas Combined Cycle (NGCC) power plant or in an Integrated Gasification Combined Cycle (IGCC) power plant, which may burn either coal or natural gas. Instead of assuming that fuel prices follow standard geometric Brownian motions, here they are assumed to show mean reversion, specifically to follow an inhomogeneous geometric Brownian motion.First we consider the opportunity to invest in a NGCC power plant. We derive the optimal investment rule as a function of natural gas price and the remaining life of the right to invest. In addition, the analytical solution for a perpetual option to invest is obtained.Then we turn to the IGCC power plant. We analyse the valuation of an operating plant when there are switching costs between modes of operation, and the choice of the best operation mode. This serves as an input to evaluate the option to invest in this plant.Finally we derive the value of an opportunity to invest either in a NGCC or IGCC power plant, i.e. to choose between an inflexible and a flexible technology, respectively. Depending on the opportunity's time to maturity, we derive the pairs of coal and gas prices for which it is optimal to invest in NGCC, in IGCC, or simply not to invest.Numerical computations involve the use of one- and two-dimensional binomial lattices that support a mean-reverting process for coal and gas prices. Basic parameter values are taken from an actual IGCC power plant currently in operation. Sensitivity of some results with respect to the underlying stochastic process for fuel price is also checked.     

Co-production of hydrogen,electricity and CO2 from coal with commercially ready technology. Part B: Economic analysis

This two-part paper investigates performances, costs and prospects of using commercially ready technology to convert coal to H₂ and electricity, with CO₂ capture and storage. Part A focuses on plant configuration, performance, and CO₂ emissions. Part B focuses on the cost of producing H₂ and electricity, with and without reduced CO₂ emissions. Our estimates show that the costs for $\sim$ 91% decarbonized energy (via quench gasification at 70 bar) are about $6.2¢/\mathrm{kWh}$ for electricity and about $ 1.0/kg (8.5  $/GJ, LHV) for hydrogen; these are, respectively, 35% and 19% higher than the corresponding energy costs with CO₂ venting. Referenced to these analogous CO₂ venting plants, the costs of CO₂ emissions avoided are $\sim$ 24 $/tonne for electricity and 11 $/tonne for H₂.     

Production of hydrogen for export from wind and solar energy,natural gas,and coal in Australia

Hydrogen production for export to Japan and Korea is increasingly popular in Australia. The theoretically possible paths include the use of the excess wind and solar energy supply to the grid to produce hydrogen from natural gas or coal. As a contribution to this debate, here I discuss the present contribution of wind and solar to the electricity grid, how this contribution might be expanded to make a grid wind and solar only, what is the energy storage needed to permit this supply, and what is the ratio of domestic total primary energy supply to electricity use. These factors are required to determine the likeliness of producing hydrogen for export. The wind and solar energy capacity, presently at 6.7 and 11.4 GW, have to increase almost 8 times up to values of 53 and 90 GW respectively to support a wind and solar energy only electricity grid for the southeast states only. Additionally, it is necessary to build-up energy storage of actual power >50 GW and stored energy >3000 GW h to stabilize the grid. If the other states and territories are considered, and also the total primary energy supply (TPES) rather than just electricity, the wind and solar capacity must be increased of a further 6–8 times. It is concluded that it is extremely unlikely that hydrogen for export could be produced from the splitting of the water molecule by using excess wind and solar energy, and it is very unlikely that wind and solar may fully cover the local TPES needs. The most likely scenario is production hydrogen via syngas from either natural gas or coal. Production from natural gas and coal needs further development of techniques, to include CO₂ capture, a way to reuse or store CO₂, and finally, the better energy efficiency of the conversion processes. There are several challenges for using natural gas or coal to produce hydrogen with near-zero greenhouse gas emissions. Carbon capture, utilization, and storage technologies that ensure no CO₂ is released in the production process, and new technologies to separate the oxygen from the air, and in case of natural gas, the water, and the CO₂ from the combustion products, are urgently needed to make sense of the fossil fuel hydrogen production. There is no benefit from producing hydrogen from fossil fuels without addressing the CO₂ issue, as well as the fuel energy penalty issue during conversion, that is simply translating in a net loss of fuel energy with the same CO₂ emission.